December 31, 20202020FY--12-31976,337,79935,402,501,369127,021,370170,478,5071,0001001,0008,546,017000110935700011681650000022606000007810000000094660001135971000007973200000278790000008192FALSEPA10 South Dearborn StreetP.O. Box 805379ChicagoIL60680-5379(800)483-3220PA300 Exelon WayKennett SquarePA19348-2473(610)765-5959IL440 South LaSalle StreetChicagoIL60605-1028(312)394-4321PAP.O. Box 86992301 Market StreetPhiladelphiaPA19101-8699(215)841-4000MD2 Center Plaza110 West Fayette StreetBaltimoreMD21201-3708(410)234-5000DE701 Ninth Street, N.W.Washington, District of Columbia20068(202)872-2000DCVA701 Ninth Street, N.W.Washington, District of Columbia20068(202)872-2000DEVA500 North Wakefield DriveNewarkDE19702(202)872-2000NJ500 North Wakefield DriveNewarkDE19702(202)872-2000Common Stock, without par valueEXCNasdaqEXC/28NYSECumulative Preferred Security, Series D,0015001500100010001001001,0001,0001,0001,00058015858047518150158181105803350570570555505805804502050575575575350575255057057557585056513155005005001111111112 years2 years5 years3 years5 years3 years5 years1 years1 years2 years1 years853541385111111730 years30 years5 years30 years5 years30 years5 years12 years4 years2 years1 years10.110.53.84.28.38.29.19.14.010.110.64.64.45.49.09.89.74.76.56.36.56.5111122111111 years1 years5 years5 years5 years823116822212512179 years5 years79 years50 years5 years2034-12-312034-12-312032-12-312033-12-312029-12-312029-12-312032-12-312031-12-312034-12-312034-12-312021-12-312021-12-312029-12-310.6501.65000.2750.2750000.07500.0750.901.2751.2751.000.900.901.0751.001.0750.002750.012750.3750.3750000000000000000000000000000P3Y0001109357exc:SmallCommercialIndustrialMemberus-gaap:RegulatedOperationMemberus-gaap:ElectricityUsRegulatedMemberexc:PecoEnergyCoMember2019-01-012019-12-310001109357exc:AtlanticCityElectricCompanyMemberus-gaap:StateAndLocalJurisdictionMember2018-01-012018-12-310001109357us-gaap:FairValueInputsLevel1Memberus-gaap:ForeignGovernmentDebtSecuritiesMemberus-gaap:FairValueMeasurementsRecurringMember2020-12-310001109357exc:BaltimoreGasAndElectricCompanyMembersrt:ParentCompanyMember2020-12-31 UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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ý | ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year Ended December 31, 20182020
or
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¨ | ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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Commission
File Number | | Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number | | IRS Employer Identification Number |
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1-16169001-16169 | | EXELON CORPORATION | | 23-2990190 |
| | (a Pennsylvania corporation)
10 South Dearborn Street
P.O. Box 805379
Chicago, Illinois 60680-5379
(800) 483-3220 | | |
| | | | |
| 333-85496 | | EXELON GENERATION COMPANY, LLC | | 23-3064219 |
| | (a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348-2473
(610) 765-5959 | | |
| | | | |
1-1839001-01839 | | COMMONWEALTH EDISON COMPANY | | 36-0938600 |
| | (an Illinois corporation)
440 South LaSalle Street
Chicago, Illinois 60605-1028
(312) 394-4321 | | |
| | | | |
| 000-16844 | | PECO ENERGY COMPANY | | 23-0970240 |
| | (a Pennsylvania corporation)
P.O. Box 8699
2301 Market Street
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000 | | |
| | | | |
1-1910001-01910 | | BALTIMORE GAS AND ELECTRIC COMPANY | | 52-0280210 |
| | (a Maryland corporation)
2 Center Plaza
110 West Fayette Street
Baltimore, Maryland 21201-3708
(410) 234-5000 | | |
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| 001-31403 | | PEPCO HOLDINGS LLC | | 52-2297449 |
| | (a Delaware limited liability company)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000 | | |
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| 001-01072 | | POTOMAC ELECTRIC POWER COMPANY | | 53-0127880 |
| | (a District of Columbia and Virginia corporation)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000 | | |
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| 001-01405 | | DELMARVA POWER & LIGHT COMPANY | | 51-0084283 |
| | (a Delaware and Virginia corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000 | | |
| | | | |
| 001-03559 | | ATLANTIC CITY ELECTRIC COMPANY | | 21-0398280 |
| | (a New Jersey corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000 | | |
Securities registered pursuant to Section 12(b) of the Act: | | | | | | | | | | | | | | |
| Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered |
| EXELON CORPORATION: | | | | |
| Common Stock, without par value | | EXC | | The Nasdaq Stock Market LLC |
| | |
Title of Each Class | | Name of Each Exchange on Which Registered |
EXELON CORPORATION: | | |
Common Stock, without par value | | New York and Chicago |
Series A Junior Subordinated Debentures | | New York |
Corporate Units | | New York |
| PECO ENERGY COMPANY: | | | | |
| Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company | | EXC/28 | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: | | |
| Title of Each Class |
| COMMONWEALTH EDISON COMPANY: |
| Common Stock Purchase Warrants (1971 Warrants and Series B Warrants) |
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Title of Each Class |
COMMONWEALTH EDISON COMPANY: |
Common Stock Purchase Warrants, 1971 Warrants and Series B Warrants |
POTOMAC ELECTRIC POWER COMPANY: |
Common Stock, $0.01 par value |
DELMARVA POWER & LIGHT COMPANY: |
Common Stock, $2.25 par value |
ATLANTIC CITY ELECTRIC COMPANY: |
Common Stock, $3.00 par value |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. |
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| Exelon Corporation | Yesx | x | | Noo | ☐ |
| Exelon Generation Company, LLC | Yesx | ☐ | | Noo | x |
| Commonwealth Edison Company | Yesx | ☐ | | Noo | x |
| PECO Energy Company | Yesx | ☐ | | Noo | x |
| Baltimore Gas and Electric Company | Yesx | ☐ | | Noo | x |
| Pepco Holdings LLC | Yesx | ☐ | | Noo | x |
| Potomac Electric Power Company | Yeso | ☐ | | No | x |
| Delmarva Power & Light Company | Yeso | ☐ | | No | x |
| Atlantic City Electric Company | Yeso | ☐ | | No | x |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. |
| | | | | | | | | | | | | | | | |
| Exelon Corporation | Yeso | ☐ | | No | x |
| Exelon Generation Company, LLC | Yeso | ☐ | | No | x |
| Commonwealth Edison Company | Yeso | ☐ | | No | x |
| PECO Energy Company | Yeso | ☐ | | No | x |
| Baltimore Gas and Electric Company | Yeso | ☐ | | No | x |
| Pepco Holdings LLC | Yeso | ☐ | | No | x |
| Potomac Electric Power Company | Yeso | ☐ | | No | x |
| Delmarva Power & Light Company | Yeso | ☐ | | No | x |
| Atlantic City Electric Company | Yeso | ☐ | | No | x |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
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| Exelon Corporation | Large Accelerated Filer | x | Accelerated Filer | ☐ | Non-accelerated Filer | ☐ | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
Exelon Corporation | x | | | | | | | | |
| Exelon Generation Company, LLC | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | xNon-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Commonwealth Edison Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | xNon-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| PECO Energy Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | xNon-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Baltimore Gas and Electric Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | xNon-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Pepco Holdings LLC | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | xNon-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Potomac Electric Power Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | xNon-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Delmarva Power & Light Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | xNon-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Atlantic City Electric Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | xNon-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act by the registered public accounting firm that prepared or issued its audit report. x
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o☐ No x
The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, 20182020 was as follows: |
| | | | |
| Exelon Corporation Common Stock, without par value | | $41,118,095,43135,402,501,369 |
| Exelon Generation Company, LLC | | Not applicable |
| Commonwealth Edison Company Common Stock, $12.50 par value | | No established market |
| PECO Energy Company Common Stock, without par value | | None |
| Baltimore Gas and Electric Company, without par value | | None |
| Pepco Holdings LLC | | Not applicable |
| Potomac Electric Power Company | | None |
| Delmarva Power & Light Company | | None |
| Atlantic City Electric Company | | None |
The number of shares outstanding of each registrant’s common stock as of January 31, 20192021 was as follows: |
| | | | |
| Exelon Corporation Common Stock, without par value | 976,337,799 | 969,745,933 |
| Exelon Generation Company, LLC | | Not applicable |
| Commonwealth Edison Company Common Stock, $12.50 par value | 127,021,370 | 127,021,331 |
| PECO Energy Company Common Stock, without par value | 170,478,507 | 170,478,507 |
| Baltimore Gas and Electric Company Common Stock, without par value | 1,000 | 1,000 |
| Pepco Holdings LLC | | Not applicable |
| Potomac Electric Power Company Common Stock, $0.01 par value | 100 | 100 |
| Delmarva Power & Light Company Common Stock, $2.25 par value | 1,000 | 1,000 |
| Atlantic City Electric Company Common Stock, $3.00 par value | 8,546,017 | 8,546,017 |
Documents Incorporated by Reference
Portions of the Exelon Proxy Statement for the 20192020 Annual Meeting of
Shareholders and the Commonwealth Edison Company 20192020 Information Statement are
incorporated by reference in Part III.
Exelon Generation Company, LLC, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form in the reduced disclosure format.
TABLE OF CONTENTS
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GLOSSARY OF TERMS AND ABBREVIATIONS | | |
FILING FORMAT | | |
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION | |
WHERE TO FIND MORE INFORMATION | |
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PART I | | |
ITEM 1. | BUSINESS | |
| General | |
| Exelon Generation Company, LLC | |
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| Employees | | |
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| PROPERTIES | | |
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| Commonwealth Edison Company | | |
| PECO Energy Company | | |
| Baltimore Gas and Electric Company | | |
| Potomac Electric Power Company | |
| Delmarva Power & Light Company | |
| Atlantic City Electric Company | |
ITEM 3. | LEGAL PROCEEDINGS | |
ITEM 4. | MINE SAFETY DISCLOSURES | |
PART II | | |
ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES | |
ITEM 6. | SELECTED FINANCIAL DATA | |
| Exelon Corporation | |
| Exelon Generation Company, LLC | |
| Commonwealth Edison Company | |
| PECO Energy Company | |
| Baltimore Gas and Electric Company | |
| Pepco Holdings LLC | |
| Potomac Electric Power Company | |
| Delmarva Power & Light Company | |
| Atlantic City Electric Company | |
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| Liquidity Considerations | |
| Other Key Business Drivers and Management Strategies | |
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| 2. Variable Interest Entities | | |
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| 4. Regulatory Matters | | |
| 5. Mergers, Acquisitions and Dispositions | | |
| 6. | |
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| 7. Impairment of Long-Lived Assets and Intangibles | |
| 8. Early Plant Retirements | |
| 9. Jointly Owned Electric Utility Plant | |
| 10. Intangible Assets | | |
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| 12. Derivative Financial Instruments | | |
| 13. Debt and Credit Agreements | |
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| 14. Income Taxes | | |
| 15. Asset Retirement Obligations | |
| 16. Retirement Benefits | |
| 17. Severance | |
| 18. Shareholders' Equity | |
| 19. Stock-Based Compensation Plans | |
| 20. Earnings Per Share | |
| 21.22. Changes in Accumulated Other Comprehensive Income | |
| 22. Commitments and Contingencies | | |
| 23. | |
| 24. Segment Information | |
| 25. Related Party Transactions | |
| 26. Quarterly Data | |
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| 27. Subsequent Events | |
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | |
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ITEM 9B. | OTHER INFORMATION | |
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PART III | | |
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ITEM 16. | FORM 10-K SUMMARY | |
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| Exelon Corporation | |
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| GLOSSARY OF TERMS AND ABBREVIATIONS |
| Exelon Corporation and Related Entities |
| Exelon | | Exelon Corporation |
| Generation | | Exelon Generation Company, LLC |
| ComEd | | Commonwealth Edison Company |
| PECO | | PECO Energy Company |
| BGE | | Baltimore Gas and Electric Company |
| Pepco Holdings or PHI | | Pepco Holdings LLC (formerly Pepco Holdings, Inc.) |
| Pepco | | Potomac Electric Power Company |
| DPL | | Delmarva Power & Light Company |
| ACE | | Atlantic City Electric Company |
| Registrants | | Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively |
| Utility Registrants | | ComEd, PECO, BGE, Pepco, DPL, and ACE, collectively |
| Legacy PHI | | PHI, Pepco, DPL, ACE, PES, and PCI, collectively |
| ACE Funding or ATF | | Atlantic City Electric Transition Funding LLC |
| Antelope Valley | | Antelope Valley Solar Ranch One |
| BondCo | | RSB BondCo LLC |
| BSC | | Exelon Business Services Company, LLC |
| CENG | | Constellation Energy Nuclear Group, LLC |
Constellation | | |
| Constellation | | Constellation Energy Group, Inc. |
| EEDC | | Exelon Energy Delivery Company, LLC |
| EGR IV | | ExGen Renewables IV, LLC |
| EGRP | | ExGen Renewables Partners, LLC |
EGTP | | ExGen Texas Power, LLC |
Entergy | | Entergy Nuclear FitzPatrick, LLC |
| Exelon Corporate | | Exelon in its corporate capacity as a holding company |
| Exelon Transmission Company | | Exelon Transmission Company, LLC |
Exelon WindFitzPatrick | | Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC |
FitzPatrick | | James A. FitzPatrick nuclear generating station |
PCIGinna | | R. E. Ginna nuclear generating station |
| NER | | NewEnergy Receivables LLC |
| PCI | | Potomac Capital Investment Corporation and its subsidiaries |
| PEC L.P. | | PECO Energy Capital, L.P. |
| PECO Trust III | | PECO Energy Capital Trust III |
| PECO Trust IV | | PECO Energy Capital Trust IV |
| Pepco Energy Services or PES | | Pepco Energy Services, Inc. and its subsidiaries |
| PHI Corporate | | PHI in its corporate capacity as a holding company |
| PHISCO | | PHI Service Company |
| RPG | | Renewable Power Generation |
| SolGen | | SolGen, LLC |
| TMI | | Three Mile Island nuclear facility |
| UII | | Unicom Investments, Inc. |
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| GLOSSARY OF TERMS AND ABBREVIATIONS |
| Other Terms and Abbreviations | | |
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GLOSSARY OF TERMS AND ABBREVIATIONS | | |
Other Terms and AbbreviationsABO | | Accumulated Benefit Obligation |
| AEC | | Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source |
| AESO | | Alberta Electric Systems Operator |
| AFUDC | | Allowance for Funds Used During Construction |
AGEAMI | | Albany Green Energy Project |
AMI | | Advanced Metering Infrastructure |
AMPAOCI | | Advanced Metering Program |
AOCI | | Accumulated Other Comprehensive Income (Loss) |
| ARC | | Asset Retirement Cost |
| ARO | | Asset Retirement Obligation |
| ARP | | Alternative Revenue Program |
| ASA | | Asset Sale Agreement |
BGS | | |
| BGS | | Basic Generation Service |
CAISOBrookfield Renewable | | California ISOBrookfield Renewable Partners, L.P. |
CAPCAISO | | Customer Assistance ProgramCalifornia ISO |
CCGTsCBAs | | Combined-Cycle gas turbinesCollective Bargaining Agreements |
| CERCLA | | Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended |
| CES | | Clean Energy Standard |
| Clean Air Act | | Clean Air Act of 1963, as amended |
| Clean Water Act | | Federal Water Pollution Control Amendments of 1972, as amended |
ConectivCODM | | Chief Operating Decision Maker |
| Conectiv | | Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE during the Predecessor periods |
Conectiv Energy | | Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine in July 2010 |
ConEdison Solutions | | The competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc., a subsidiary of Consolidated Edison, Inc |
CSAPR | | Cross-State Air Pollution Rule |
CTA | | Consolidated tax adjustment |
D.C. Circuit Court | | United States Court of Appeals for the District of Columbia Circuit |
| DC PLUG | | District of Columbia Power Line Undergrounding Initiative |
| DCPSC | | District of Columbia Public Service Commission |
DDOT | | District Department of Transportation |
| DOE | | United States Department of Energy |
| DOEE | | Department of Energy & Environment |
| DOJ | | United States Department of Justice |
DPSCDPP | | Deferred Purchase Price |
| DPSC | | Delaware Public Service Commission |
DSP | | |
| DSP | | Default Service Provider |
DSP ProgramEDF | | Default Service Provider Program |
EDF | | Electricite de France SA and its subsidiaries |
EIMA | | |
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| EIMA | | Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036) |
EmPowerEPA | | A Maryland demand-side management program for Pepco and DPL |
EPA | | United States Environmental Protection Agency |
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| ERCOT | | |
GLOSSARY OF TERMS AND ABBREVIATIONS |
Other Terms and Abbreviations | | |
EPSA | | Electric Power Supply Association |
ERCOT | | Electric Reliability Council of Texas |
| ERISA | | Employee Retirement Income Security Act of 1974, as amended |
| EROA | | Expected Rate of Return on Assets |
FASB | | |
| ERP | | Enterprise Resource Program |
| FASB | | Financial Accounting Standards Board |
| FEJA | | Illinois Public Act 99-0906 or Future Energy Jobs Act |
| FERC | | Federal Energy Regulatory Commission |
| FRCC | | Florida Reliability Coordinating Council |
GAAPFRR | | Fixed Resource Requirement |
| GAAP | | Generally Accepted Accounting Principles in the United States |
| GCR | | Gas Cost Rate |
| GHG | | Greenhouse Gas |
| GSA | | Generation Supply Adjustment |
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GWh | | Gigawatt hourGLOSSARY OF TERMS AND ABBREVIATIONS |
IBEWOther Terms and Abbreviations | | International Brotherhood of Electrical Workers |
ICCGWh | | Gigawatt hour |
| ICC | | Illinois Commerce Commission |
| ICE | | Intercontinental Exchange |
| IIP | | Infrastructure Investment Program |
Illinois EPA | | Illinois Environmental Protection Agency |
| Illinois Settlement Legislation | | Legislation enacted in 2007 affecting electric utilities in Illinois |
IntegrysIPA | | Integrys Energy Services, Inc. |
IPA | | Illinois Power Agency |
| IRC | | Internal Revenue Code |
| IRS | | Internal Revenue Service |
| ISO | | Independent System Operator |
| ISO-NE | | ISO New England Inc. |
ISO-NYNYISO | | ISO New York ISO |
| kV | | Kilovolt |
kWkWh | | KilowattKilowatt-hour |
kWhLIBOR | | Kilowatt-hour |
LIBOR | | London Interbank Offered Rate |
| LLRW | | Low-Level Radioactive Waste |
| LNG | | Liquefied Natural Gas |
LTIP | | |
| LTIP | | Long-Term Incentive Plan |
MAPPMATS | | Mid-Atlantic Power Pathway |
MATS | | U.S. EPA Mercury and Air Toxics RuleStandards |
MBRMDE | | Market Based Rates Incentive |
MDE | | Maryland Department of the Environment |
| MDPSC | | Maryland Public Service Commission |
| MGP | | Manufactured Gas Plant |
| MISO | | Midcontinent Independent System Operator, Inc. |
| mmcf | | Million Cubic Feet |
Moody’s | | Moody’s Investor Service |
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| MOPR | | |
GLOSSARY OF TERMS AND ABBREVIATIONS |
Other Terms and Abbreviations | | |
MOPR | | Minimum Offer Price Rule |
| MRV | | Market-Related Value |
| MW | | Megawatt |
| MWh | | Megawatt hour |
n.m.N/A | | not meaningfulNot applicable |
NAAQSNAV | | National Ambient Air Quality Standards |
NAV | | Net Asset Value |
| NDT | | Nuclear Decommissioning Trust |
| NEIL | | Nuclear Electric Insurance Limited |
| NERC | | North American Electric Reliability Corporation |
NGSNJBPU | | Natural Gas Supplier |
NJBPU | | New Jersey Board of Public Utilities |
| NJDEP | | New Jersey Department of Environmental Protection |
NLRBNon-Regulatory Agreement Units | | National Labor Relations Board |
Non-Regulatory Agreements Units | | Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting |
| NOSA | | Nuclear Operating Services Agreement |
| NPDES | | National Pollutant Discharge Elimination System |
NRCNPNS | | Normal Purchase Normal Sale scope exception |
| NRC | | Nuclear Regulatory Commission |
NSPS | | New Source Performance Standards |
| NWPA | | Nuclear Waste Policy Act of 1982 |
| NYMEX | | New York Mercantile Exchange |
| NYPSC | | New York Public Service Commission |
| OCI | | Other Comprehensive Income |
| OIESO | | Ontario Independent Electricity System Operator |
OPCOPEB | | Office of People’s Counsel |
OPEB | | Other Postretirement Employee Benefits |
| | |
| | | | | | | | |
| GLOSSARY OF TERMS AND ABBREVIATIONS |
| Other Terms and Abbreviations | | |
| PA DEP | | Pennsylvania Department of Environmental Protection |
| PAPUC | | Pennsylvania Public Utility Commission |
| PCB | | Polychlorinated Biphenyl |
| PGC | | Purchased Gas Cost Clause |
PJM | | |
| PG&E | | Pacific Gas and Electric Company |
| PJM | | PJM Interconnection, LLC |
| POLR | | Provider of Last Resort |
PORPPA | | Purchase of Receivables |
PPA | | Power Purchase Agreement |
| PP&E | | Property, Plant, and Equipment |
| Price-Anderson Act | | Price-Anderson Nuclear Industries Indemnity Act of 1957 |
Preferred StockPRP | | Originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share |
PRP | | Potentially Responsible Parties |
| PSEG | | Public Service Enterprise Group Incorporated |
| PV | | Photovoltaic |
| RCRA | | Resource Conservation and Recovery Act of 1976, as amended |
|
| REC | | |
GLOSSARY OF TERMS AND ABBREVIATIONS |
Other Terms and Abbreviations | | |
REC | | Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source |
| Regulatory Agreement Units | | Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting |
| RES | | Retail Electric Suppliers |
| RFP | | Request for Proposal |
| Rider | | Reconcilable Surcharge Recovery Mechanism |
| RGGI | | Regional Greenhouse Gas Initiative |
| RMC | | Risk Management Committee |
| RNF | | Revenue Net of Purchased Power and Fuel Expense |
| ROE | | Return on equity |
RPMROU | | PJM Reliability Pricing ModelRight-of-use |
| RPS | | Renewable Energy Portfolio Standards |
RSSARTEP | | Reliability Support Services Agreement |
RTEP | | Regional Transmission Expansion Plan |
| RTO | | Regional Transmission Organization |
| S&P | | Standard & Poor’s Ratings Services |
| SEC | | United States Securities and Exchange Commission |
SERC | | |
| SERC | | SERC Reliability Corporation (formerly Southeast Electric Reliability Council) |
| SGIG | | Smart Grid Investment Grant from DOE |
SILOSNF | | Sale-In, Lease-Out |
SNF | | Spent Nuclear Fuel |
SOSSOA | | Society of Actuaries |
| SOS | | Standard Offer Service |
SPFPASPP | | Security, Police and Fire Professionals of America |
SPP | | Southwest Power Pool |
TCJASSA | | Social Security Administration |
| TCJA | | Tax Cuts and Jobs Act
|
| Transition Bond Charge | | Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses, and fees |
| Transition Bonds | | Transition Bonds issued by ACE Funding |
UpstreamU.S. Court of Appeals for the D.C. Circuit | | Natural gas and oil exploration and production activitiesUnited States Court of Appeals for the District of Columbia Circuit |
| VIE | | Variable Interest Entity |
| WECC | | Western Electric Coordinating Council |
| | | | | | | | |
ZECGLOSSARY OF TERMS AND ABBREVIATIONS |
| Other Terms and Abbreviations | | |
| ZEC | | Zero Emission Credit |
| ZES | | Zero Emission Standard |
FILING FORMAT
This combined Annual Report on Form 10-K is being filed separately by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. uncertainties including, among others, those related to the timing, manner, tax-free nature and expected benefits associated with the potential separation of Exelon’s competitive power generation and customer-facing energy business from its six regulated electric and gas utilities. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic and financial performance, are intended to identify such forward-looking statements.
The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, including those factors discussed with respect to the Registrants discussed in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 22,19, Commitments and Contingencies;Contingencies, and (d) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
WHERE TO FIND MORE INFORMATION
The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and the Registrants’ website at www.exeloncorp.com. Information contained on the Registrants’ website shall not be deemed incorporated into, or to be a part of, this Report.
PART I
General
Corporate Structure and Business and Other Information
Exelon incorporated in Pennsylvania in February 1999, is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation inand the energy generation business,distribution and transmission businesses through ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE in the energy delivery businesses discussed below. Exelon’s principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603.
|
| | | | | | | | | | | | | |
| Name of Registrant | | State/Jurisdiction andBusiness | | Business | | Service | | Address of Principal |
Year of Incorporation | Territories | Executive Offices |
Exelon Generation
Company, LLC
| | Pennsylvania (2000) | | Generation, physical delivery, and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy, and other energy-related products and services.
| | SixFive reportable segments: Mid-Atlantic, Midwest, New England, New York, ERCOT, and Other Power Regions | | 300 Exelon Way,
Kennett Square, Pennsylvania 19348
|
| | | | | | | | |
| Commonwealth Edison Company | | Illinois (1913) | | Purchase and regulated retail sale of electricity | | Northern Illinois, including the City of Chicago | | 440 South LaSalle Street,
Chicago, Illinois 60605
|
| | | | Transmission and distribution of electricity to retail customers | | | | |
| PECO Energy Company | | Pennsylvania (1929) | | Purchase and regulated retail sale of electricity and natural gas | | Southeastern Pennsylvania, including the City of Philadelphia (electricity) | | 2301 Market Street,
Philadelphia, Pennsylvania 19103
|
| | | | Transmission and distribution of electricity and distribution of natural gas to retail customers | | Pennsylvania counties surrounding the City of Philadelphia (natural gas) | | |
| Baltimore Gas and Electric Company | | Maryland (1906) | | Purchase and regulated retail sale of electricity and natural gas | | Central Maryland, including the City of Baltimore (electricity and natural gas) | | 110 West Fayette Street,
Baltimore, Maryland 21201
|
| | | | Transmission and distribution of electricity and distribution of natural gas to retail customers | | | | |
| Pepco Holdings LLC | | Delaware (2016) | | Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE | | Service Territories of Pepco, DPL, and ACE | | 701 Ninth Street, N.W.,
Washington, D.C. 20068 |
| | | | | | | | |
Potomac Electric
Power Company
| | District of Columbia
(1896)
Virginia (1949)
| | Purchase and regulated retail sale of electricity | | District of Columbia and Major portions of Montgomery and Prince George’s Counties, Maryland | | 701 Ninth Street, N.W.,
Washington, D.C. 20068
|
| | | | Transmission and distribution of electricity to retail customers | | | | |
| Delmarva Power & Light Company | | Delaware (1909)
Virginia (1979)
| | Purchase and regulated retail sale of electricity and natural gas | | Portions of Delaware and Maryland (electricity) | | 500 North Wakefield Drive,
Newark, Delaware 19702
|
| | | | Transmission and distribution of electricity and distribution of natural gas to retail customers | | Portions of New Castle County, Delaware (natural gas) | | |
| Atlantic City Electric Company | | New Jersey (1924) | | Purchase and regulated retail sale of electricity | | Portions of Southern New Jersey | | 500 North Wakefield Drive,
Newark, Delaware 19702
|
| | | | Transmission and distribution of electricity to retail customers | | | | |
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Business Services
Through its business services subsidiary, BSC, Exelon provides its operating subsidiaries with a variety of corporate governance support services at cost, including corporate strategy and development, legal, human resources, financial, information technology, finance, real estate, security, corporate communications and supply at cost. The costs of thesemanagement services. PHI also has a business services are directly charged or allocated to the applicable operating segments. The services are provided pursuant to service agreements. Additionally, the results of Exelon’s corporate operations include interest costs and income from various investment and financing activities.
subsidiary, PHISCO, a wholly owned subsidiary of PHI,which provides a variety of support services at cost, including legal, finance,accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and its operating subsidiaries. These servicesPHISCO are directly charged or allocated pursuant to service agreements among PHISCOthe applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and the participating operating subsidiaries.include intercompany eliminations unless otherwise disclosed.
Merger with Pepco Holdings, Inc. (Exelon)On March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary
Generation
Generation, one of the largest competitive electric generation companies in the United States as measured by owned and contracted MW, physically delivers and markets power across multiple geographic regions through its customer-facing business, Constellation. Constellation sells electricity and natural gas, including renewable energy, in competitive energy markets to both wholesale and retail customers. Generation leverages its energy generation portfolio to ensure delivery of energy to both wholesale and retail customers under long-term and short-term contracts, and in wholesale power markets. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Generation's fleet also provides geographic and supply source diversity. Generation’s customers include distribution utilities, municipalities, cooperatives, financial institutions, and commercial, industrial, governmental, and residential customers in competitive markets. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers.
Generation is a public utility under the Federal Power Act and is subject to FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates for sales of energy, capacity, and ancillary services to ensure that such sales are just and reasonable. FERC’s jurisdiction over ratemaking includes the authority to suspend the market-based rates of utilities and set cost-based rates should FERC find that its previous grant of market-based rates authority is no longer just and reasonable. Other matters subject to FERC jurisdiction include, but are not limited to, third-party financings; review of mergers; dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility; affiliate transactions; intercompany financings and cash management arrangements; certain internal corporate reorganizations; and certain holding company acquisitions of public utility and holding company securities.
RTOs and ISOs exist in a number of regions to provide transmission service across multiple transmission systems. FERC has approved PJM, MISO, ISO-NE, and SPP as RTOs and CAISO and ISO-NYNYISO as ISOs. These entities are responsible for regional planning, managing transmission congestion, developing wholesale markets for energy and capacity, maintaining reliability, market monitoring, the scheduling of physical power sales brokered through ICE and NYMEX, and the elimination or reduction of redundant transmission charges imposed by multiple transmission providers when wholesale customers take transmission service across several transmission systems.
ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC.
Specific operations of Generation are also subject to the jurisdiction of various other Federal, state, regional, and local agencies, including the NRC, and Federal and state environmental protection agencies. Additionally, Generation is subject to NERC mandatory reliability standards, which protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches.
Generation owns a 50.01% interest in CENG, a joint venture with EDF. CENG is governed by a board of ten directors, five of which are appointed by Generation and five by EDF. CENG owns a total of five nuclear generating facilities on three sites, Calvert Cliffs, R.E. Ginna (Ginna) and Nine Mile Point. CENG’s ownership share in the total capacity of these units is 4,041 MW. See ITEM 2. PROPERTIES for additional information on these sites.
Generation and EDF entered into a Put Option Agreement on April 1, 2014, pursuant to which EDF has the option, exercisable beginning on January 1, 2016 and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determined by agreement of the parties, or absent agreement, a third-party arbitration process. The appraisers determining fair market value of EDF’s 49.99% interest in CENG under the Put Option Agreement are instructed to take into account all rights and obligations under the CENG Operating Agreement, including Generation’s rights with respect to any unpaid aggregate preferred distributions and the related return, and the value of Generation’s rights to other distributions. In addition, under limited circumstances, the period for exercise of the put option may be extended for 18 months. In order to exercise its option, EDF must give 60-days advance written notice to Generation stating that it is exercising its option. To date, EDF has not given notice to Generation that it is exercising its option.
Exelon and Generation record all assets, liabilities and EDF’s noncontrolling interests in CENG on a fully consolidated basis in Exelon’s and Generation’s Consolidated Balance Sheets. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the CENG consolidation.
Acquisitions
Handley Generating Station
On April 4, 2018, Generation acquired the Handley Generating Station in conjunction with the EGTP Chapter 11 proceedings for a total purchase price of $62 million. See EGTP in the Dispositions section below for additional information on EGTP's November 7, 2017 bankruptcy filing.
FitzPatrick
On March 31, 2017, Generation acquired the 838 MW single-unit FitzPatrick plant located in Scriba, New York from Entergy for a total purchase price consideration of $289 million, resulting in an after-tax bargain purchase gain of $233 million in 2017.
ConEdison Solutions
On September 1, 2016, Generation acquired ConEdison Solutions for a purchase price of $257 million, including net working capital of $204 million. The renewable energy, sustainable services and energy efficiency businesses of ConEdison were excluded from the transaction.
Integrys Energy Services, Inc.
On November 1, 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys Energy Group, Inc. through the purchase of all of the stock of its wholly owned subsidiary, Integrys Energy Services, Inc. (Integrys) for a purchase price of $332 million, including net working capital. The generation and solar asset businesses of Integrys were excluded from the transaction.
Dispositions
EGTP
On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware. As a result of the bankruptcy filing, EGTP’s assets and liabilities were deconsolidated from Exelon and Generation's consolidated financial statements. The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders.
Asset Dispositions
During 2015 and 2014, Generation sold certain generating assets with total pre-tax proceeds of $1.8 billion (after-tax proceeds of approximately $1.4 billion). Proceeds were used primarily to finance a portion of the acquisition of PHI.
See Note 5 — Mergers, Acquisitions and Dispositions and Note 7 — Impairment of Long-Lived Assets and Intangibles of the Combined Notes to Consolidated Financial Statements for additional information on acquisitions and dispositions.
Generating Resources
At December 31, 2018,2020, the generating resources of Generation consisted of the following:
|
| | | | |
| Type of Capacity | MW |
Owned generation assets(a)(b) | |
| Nuclear | 19,71318,880 |
|
| Fossil (primarily natural gas and oil) | 9,547 |
|
Renewable(c)
| 3,203 |
|
Owned generation assets | 32,463 |
|
Long-term power purchase contracts(d)
| 5,184 |
|
Total generating resources | 37,647 |
|
__________
| 9,340 | |
(a) Renewable(c) | See “Fuel” for sources of fuels used in electric generation. |
| 3,051 | |
(b)Owned generation assets | Net generation capacity is stated at proportionate ownership share. See ITEM 2. PROPERTIES—Generation for additional information. |
| 31,271 | |
(c)Contracted generation(d) | Includes wind, hydroelectric, solar and biomass generating assets. |
| 3,966 | |
(d)Total generating resources | Electric supply procured under site specific agreements.35,237 | |
__________
(a)See “Fuel” for sources of fuels used in electric generation.
(b)Net generation capacity is stated at proportionate ownership share. See ITEM 2. PROPERTIES—Generation for additional information.
(c)Includes wind, hydroelectric, solar, and biomass generation.
(d)Electric supply procured under site specific agreements.
Generation has sixfive reportable segments, Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions,as described in the table below, representing the different geographical areas in which Generation’s owned generating resources are located and Generation's customer-facing activities are conducted.
Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of North Carolina (approximately 34% of capacity).
| | | | | | | | | | | | | | | | | | | | |
| Segment | | Net Generation Capacity (MW)(a) | | % of Net Generation Capacity | | Geographical Area |
| Mid-Atlantic | | 9,729 | | | 31 | % | | Eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina |
| Midwest | | 11,911 | | | 38 | % | | Western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region |
| New York | | 1,971 | | | 6 | % | | NYISO |
| ERCOT | | 3,623 | | | 12 | % | | Electric Reliability Council of Texas |
| Other Power Regions | | 4,037 | | | 13 | % | | New England, South, West, and Canada |
| Total | | 31,271 | | | 100 | % | | |
Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region (approximately 37% of capacity).
__________New England represents operations within ISO-NE (approximately 7% of capacity).
New York represents operations within ISO-NY (approximately 6% of capacity).
ERCOT represents operations within Electric Reliability Council of Texas (approximately 11% of capacity).
Other Power Regions represents Canada, South and West (approximately 5% of capacity).
During the first quarter of 2019, due to a change in economics in our New England region, Generation(a)Net generation capacity is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation will disclose five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions.stated at proportionate ownership share. See Note 24 - Segment Information of the Combined Notes to Consolidated Financial StatementsITEM 2. PROPERTIES—Generation for additional information.
Nuclear Facilities
Generation has ownership interests in fourteenthirteen nuclear generating stations currently in service, consisting of 2423 units with an aggregate of 19,71318,880 MW of capacity. These stations include FitzPatrick located in Scriba, New York, which was acquired on March 31, 2017 and exclude TMI located in Middletown, Pennsylvania, which permanently ceased generation operations on September 20, 2019 and Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018 and was subsequently sold to Holtec International (Holtec) on July 1, 2019. Generation wholly owns all of its nuclear generating stations, except for undivided ownership interests in three jointly-owned nuclear stations: Quad Cities (75% ownership), Peach Bottom (50% ownership), and Salem (42.59% ownership), which are consolidated in Exelon’s and Generation's financial statements relative to its proportionate ownership interest in each unit, and a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owns the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point [excluding Long Island Power Authority's 18%Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2] and Ginna nuclear stations.2. CENG is 100% consolidated in Exelon's and Generation’sGeneration's financial statements.
Generation and EDF entered into a Put Option Agreement on April 1, 2014, pursuant to which EDF has an option to sell its 49.99% equity interest in CENG to Generation. The put option became exercisable on January 1, 2016 and may be exercised any time until June 30, 2022. On November 20, 2019, Generation received notice of EDF’s intention to exercise the put option and sell its ownership share in CENG to Generation and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. At this time, Generation cannot reasonably predict the ultimate purchase price that will be paid to EDF for its interest in CENG. The transaction will require approval by the NYPSC and the FERC. The FERC approval was obtained on July 30, 2020. From the date the put was exercised, the process and regulatory approvals could take one to two years to complete.
See ITEM 2. PROPERTIES for additional information on Generation's nuclear facilities, Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the disposition of Oyster Creek, and Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the CENG consolidation.
Generation’s nuclear generating stations are all operated by Generation, with the exception of the two units at Salem, which are operated by PSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. In 2018, 20172020, 2019, and 20162018 electric supply (in GWh) generated from the nuclear generating facilities was 68%62%, 69%64%, and 67%68%, respectively, of Generation’s total electric supply, which also includes fossil, hydroelectric, and renewable generation and electric supply purchased for resale. Generation’s wholesale and retail power marketing activities are, in part, supplied by the output from the nuclear generating stations. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information of Generation’s electric supply sources.
Nuclear Operations
Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, can have a significant impact on Generation’s results of operations. Generation’s operations from its nuclear plants have historically had minimal environmental impact and the plants have a safe operating history.
During 2018, 2017 and 2016, the nuclear generating facilities operated by Generation achieved capacity factors of 94.6%, 94.1% and 94.6%, respectively. The capacity factors reflect ownership percentage of stations operated by Generation and include CENG. Generation manages its scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable generation base for Generation’s wholesale and retail power marketing activities. During scheduled refueling outages, Generation performs maintenance and equipment upgrades in order to minimize the occurrence of unplanned outages and to maintain safe, reliable operations. During 2020, 2019, and 2018, the nuclear generating facilities operated by Generation, achieved capacity factors of 95.4%, 95.7%, and 94.6%, respectively, at ownership percentage.
In addition to the maintenance and equipment upgrades performed by Generation during scheduled refueling outages, Generation has extensive operating and security procedures in place to ensure the safe operation of the nuclear units. Generation also has extensive safety systems in place to protect the plant, personnel, and surrounding area in the unlikely event of an accident or other incident.
Regulation of Nuclear Power Generation
Generation is subject to the jurisdiction of the NRC with respect to the operation of its nuclear generating stations, including the licensing for operation of each unit. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security, and environmental and radiological aspects of those stations. As part of its reactor oversight process, the NRC continuously assesses unit performance indicators and inspection results and communicates its assessment on a semi-annual basis. All nuclear generating stations operated by Generation except for Peach Bottom Units 2 and 3, are categorized by the NRC in the Licensee Response Column, which is the highest of five performance bands. As of January 29, 2019, the NRC categorized Peach Bottom Units 2 and 3 in the Regulatory Response Column, which is the second highest of five performance bands. The NRC may modify, suspend, or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act the regulations under such Act or the
terms of the operating licenses. Changes in regulations by the NRC may require a substantial increase in capital expenditures and/or operating costs for nuclear generating facilities.
Licenses
Generation has original 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals from the NRC for all its nuclear units except Clinton. Additionally, PSEG has received 20-year operating license renewals for Salem Units 1 and 2. Peach Bottom has received a second 20-year license
renewal from the NRC for Units 2 and 3. On August 27, 2020, Generation announced that it intends to permanently cease generation operations at Byron in September 2021 and at Dresden in November 2021. See Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
The following table summarizes the current license expiration dates for Generation’s operating nuclear facilities in service:
| | | Station | Unit | | In-Service Date(a) | | Current License Expiration | Station | Unit | | In-Service Date(a) | | Current License
Expiration |
| Braidwood | 1 |
| | 1988 | | 2046 | Braidwood | 1 | | | 1988 | | 2046 |
| | 2 |
| | 1988 | | 2047 | | 2 | | | 1988 | | 2047 |
| Byron | 1 |
| | 1985 | | 2044 | Byron | 1 | | | 1985 | | 2044 |
| | 2 |
| | 1987 | | 2046 | | 2 | | | 1987 | | 2046 |
| Calvert Cliffs | 1 |
| | 1975 | | 2034 | Calvert Cliffs | 1 | | | 1975 | | 2034 |
| | 2 |
| | 1977 | | 2036 | | 2 | | | 1977 | | 2036 |
Clinton(b) | 1 |
| | 1987 | | 2026 | Clinton(b) | 1 | | | 1987 | | 2027 |
| Dresden | 2 |
| | 1970 | | 2029 | Dresden | 2 | | | 1970 | | 2029 |
| | 3 |
| | 1971 | | 2031 | | 3 | | | 1971 | | 2031 |
| FitzPatrick | 1 |
| | 1974 | | 2034 | FitzPatrick | 1 | | | 1974 | | 2034 |
| LaSalle | 1 |
| | 1984 | | 2042 | LaSalle | 1 | | | 1984 | | 2042 |
| | 2 |
| | 1984 | | 2043 | | 2 | | | 1984 | | 2043 |
| Limerick | 1 |
| | 1986 | | 2044 | Limerick | 1 | | | 1986 | | 2044 |
| | 2 |
| | 1990 | | 2049 | | 2 | | | 1990 | | 2049 |
| Nine Mile Point | 1 |
| | 1969 | | 2029 | Nine Mile Point | 1 | | | 1969 | | 2029 |
| | 2 |
| | 1988 | | 2046 | | 2 | | | 1988 | | 2046 |
Peach Bottom(c) | 2 |
| | 1974 | | 2033 | |
| Peach Bottom | | Peach Bottom | 2 | | | 1974 | | 2053 |
| | 3 |
| | 1974 | | 2034 | | 3 | | | 1974 | | 2054 |
| Quad Cities | 1 |
| | 1973 | | 2032 | Quad Cities | 1 | | | 1973 | | 2032 |
| | 2 |
| | 1973 | | 2032 | | 2 | | | 1973 | | 2032 |
| Ginna | 1 |
| | 1970 | | 2029 | Ginna | 1 | | | 1970 | | 2029 |
| Salem | 1 |
| | 1977 | | 2036 | Salem | 1 | | | 1977 | | 2036 |
| | 2 |
| | 1981 | | 2040 | | 2 | | | 1981 | | 2040 |
Three Mile Island(d) | 1 |
| | 1974 | | 2034 | |
__________
| |
(a) | Denotes year in which nuclear unit began commercial operations. |
| |
(b) | Although timing has been delayed, Generation currently plans to seek license renewal for Clinton and has advised the NRC that any license renewal application would not be filed until the first quarter of 2021. |
| |
(c) | On July 10, 2018, Generation submitted a second 20-year license renewal application to NRC for Peach Bottom Units 2 and 3. |
| |
(d) | On May 30, 2017, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019 and has notified the NRC. See Note 8 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information. |
(a)Denotes year in which nuclear unit began commercial operations.
(b)Although timing has been delayed, Generation currently plans to seek license renewal for Clinton and has notified the NRC that any license renewal application would not be filed until the first quarter of 2024. In 2019, the NRC approved a change of the operating license expiration for Clinton from 2026 to 2027.
The operating license renewal process takes approximately four to five years from the commencement of the renewal process, which includes approximately two years for Generation to develop the application and approximately two years for the NRC to review the application. To date, each granted license renewal has been for 20 years beyond the original operating license expiration. Depreciation provisions are based on the estimated useful lives of the
stations, which reflect the actualfirst renewal of the operating licenses for all of Generation’s operating nuclear generating stations except for TMIClinton, Peach Bottom, Byron, and Clinton. Beginning in 2017, TMI depreciation provisions are based on its 2019 expected shutdown date. Beginning in 2016,Dresden. Clinton depreciation provisions are based on an estimated useful life of 2027 which is the last year of the Illinois Zero Emissions Standard.ZES. Peach Bottom depreciation provisions are based on estimated useful life of 2053 and 2054 for Unit 2 and Unit 3, respectively, which reflects the second renewal of its operating licenses. Byron and Dresden depreciation provisions are based on the announced shutdown dates of September 2021 and November 2021, respectively. See Note 4 -3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on FEJAthe Illinois ZES and Note 87 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information on early retirements.
Nuclear Waste Storage and Disposal
There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by its nuclear generating facilities on-site in storage pools or in dry cask storage facilities. Since Generation’s SNF storage pools generally do not have sufficient storage capacity for the life of the respective plant, Generation has developed dry cask storage facilities to support operations.
As of December 31, 2018,2020, Generation had approximately 87,100 SNF assemblies (21,400(21,600 tons) stored on site in SNF pools or dry cask storage which includes SNF assemblies at Zion Station, for which Generation retains ownership even though the responsibility for decommissioning Zion Station has been assumed by another party, and Oyster Creek,TMI, which is no longer operational. See the Decommissioning section below for additional information regarding Zion Station and Oyster Creek.Station. All currently operating Generation-owned nuclear sites have on-site dry cask storage, except for TMI, where suchstorage. TMI's on-site dry cask storage is projected to be in operation in 2021. On-site dry cask storage in concert with on-site storage pools will be capable of meeting all current and future SNF storage requirements at Generation’s sites through the end of the license renewal periods and through decommissioning.
For a discussion of matters associated with Generation’s contracts with the DOE for the disposal of SNF, see Note 2219 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
As a by-product of their operations, nuclear generating units produce LLRW. LLRW is accumulated at each generating station and permanently disposed of at licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 provides that states may enter into agreements to provide regional disposal facilities for LLRW and restrict use of those facilities to waste generated within the region. Illinois and Kentucky have entered into such an agreement, although neither state currently has an operational site and none is anticipated to be operational until after 2020.for the next ten years.
Generation ships its Class A LLRW, which represents 93% of LLRW generated at its stations, to disposal facilities in Utah and South Carolina, which have enough storage capacity to store all Class A LLRW for the life of all stations in Generation's nuclear fleet. The disposal facility in South Carolina at present is only receiving LLRW from LLRW generators in South Carolina, New Jersey (which includes Oyster Creek and Salem), and Connecticut.
Generation utilizes on-site storage capacity at all its stations to store and stage for shipping Class B and Class C LLRW. Generation has a contract through 2032 to ship Class B and Class C LLRW to a disposal facility in Texas. The agreement provides for disposal of all current Class B and Class C LLRW currently stored at each station as well as the Class B and Class C LLRW generated during the term of the agreement. However, because the production of LLRW from Generation’s nuclear fleet will exceed the capacity at the Texas site (3.9 million curies for 15 years beginning in 2012), Generation will still be required to utilize on-site storage at its stations for Class B and Class C LLRW. Generation currently has enough storage capacity to store all Class B and Class C LLRW for the life of all stations in Generation’s nuclear fleet. Generation continues to pursue alternative disposal strategies for LLRW, including an LLRW reduction program to minimize on-site storage and cost impacts.
Nuclear Insurance
Generation is subject to liability, property damage, and other risks associated with major incidents at anyall of its nuclear stations, including the CENG nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions. See “Nuclear Insurance” within Note 2219 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
For information regarding property insurance, see ITEM 2. PROPERTIES — Generation. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained or are within the policy deductible for its insured losses. Such losses could have a material adverse effect on Exelon’s and Generation’s future financial statements.
Decommissioning
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility. The ultimate decommissioning obligation will be funded by the NDTs. The NDTs are recorded in Exelon’s and Generation’s Consolidated Balance Sheets at December 31, 2018 at fair value of approximately $12.7 billion and have an estimated targeted annual pre-tax return of 5% to 6.2%, while the Nuclear AROs are recorded in Exelon’s and Generation’s Consolidated Balance Sheets at December 31, 2018 at approximately $10.0 billion and have an estimated annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units. The NDTs and AROs include Oyster Creek balances classified as Assets held for sale and Liabilities held for sale, respectively, in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018.NDT funds. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS — Exelon Corporation, Executive Overview;Liquidity and Capital Resources; ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Critical Accounting Policies and Estimates, Nuclear Decommissioning, Asset Retirement Obligations, and Nuclear Decommissioning Trust Fund Investments; and Note 43 — Regulatory Matters, Note 5 - 2 — Mergers, Acquisitions, and Dispositions, Note 1118 — Fair Value of Financial Assets and Liabilities, and Note 1510 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding Generation’s NDT funds and its decommissioning obligations.
Oyster Creek Generating StationDecommissioning. On July 31, 2018,1, 2019, Generation entered into an agreementcompleted the sale with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for the sale and decommissioning of Oyster Creek located in Forked River, New Jersey. On September 17, 2018, Oyster Creek permanently ceased generation operations.under which Holtec has assumed the responsibility for decommissioning. See Note 5 - 2 — Mergers, Acquisitions, and Dispositions and Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding the sale of Oyster Creek.information.
Zion Station Decommissioning. On September 1, 2010, Generation completed an Asset Sale Agreement (ASA)ASA with EnergySolutions, Inc. and its wholly owned subsidiaries, EnergySolutions, LLC and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station.
Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation’s transfer of those assets, ZionSolutions assumed decommissioning and other liabilities, excluding the obligation to dispose of SNF, associated with Zion Station. Pursuant to the ASA, ZionSolutions will periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to the decommissioning efforts at Zion Station. However, ZionSolutions is subject to certain restrictions on its ability to request reimbursement; specifically, if certain milestones as defined in the ASA are not met, all or a portion of requested reimbursements will be deferred until such milestones are met. See Note 1510 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding Zion Station decommissioning and Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for a discussion of variable interest entity considerations related to ZionSolutions.information.
Fossil and Renewable Facilities (including Hydroelectric)
At December 31, 2018, Generation had ownership interests in 12,750 MW of capacity in generating facilities currently in service, consisting of 9,547 MW of natural gas and oil, and 3,203 MW of renewables (wind, hydroelectric, solar and biomass). Generation wholly owns all of its fossil and renewable generating stations, with the exception of: (1) Wyman; (2) certain wind project entities and a biomass project entity with minority interest owners; and (3) EGRP which is owned 49% by another owner. See Note 223 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding certain of these entitiesEGRP which are VIEs.is a VIE. Generation’s fossil and renewable generating stations are all operated by Generation, with the exception of Wyman, which is operated by a third party. In 2018, 20172020, 2019, and 2016,2018, electric supply (in GWh) generated from owned fossil and renewable generating facilities was 9%, 11%, 12% and 10%11%, respectively, of Generation’s total electric supply. The majority of this output was dispatched to support Generation’s wholesale and retail power marketing activities. ForOn December 8, 2020, Generation entered into an agreement to sell a significant portion of Generation's solar business. See ITEM 2. PROPERTIES for additional information regarding Generation’sGeneration's electric generating facilities see ITEM 2. PROPERTIES — Exelon Generation Company, LLC and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Exelon Corporation, Executive OverviewNote 2 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on Generation Renewable Development.
the sale of Generation's solar business.
Licenses
Fossil and renewable generation plants are generally not licensed, and, therefore, the decision on when to retire plants is, fundamentally, a commercial one. FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways or Federal lands, or connected to the interstate electric grid, which include Generation's Conowingo Hydroelectric Project (Conowingo) and Muddy Run Pumped Storage Facility Project (Muddy Run). Muddy Run's license expires on December 1, 2055. On August 29, 2012, Generation submitted a hydroelectric license application to the FERC for a 46-yearnew license for Conowingo. Based on the FERC procedural schedule, the FERC licensing process for Conowingo was not completed prior to the expiration of the plant’s license on September 1, 2014. As a result, on September 10, 2014, FERC issued an annual license for Conowingo, effective as of the expiration of the previous license. The annual license renews automatically absent any further FERC action. The stations are currently being depreciated over their estimated useful lives, which includesinclude actual and anticipated license renewal periods. See Note 43 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.information on Conowingo.
Insurance
Generation maintains business interruption insurance for its renewable projects, but not for its fossil and hydroelectric operations unless required by contract or financing agreements. See Note 1317 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on financing agreements. Generation maintains both property damage and liability insurance. For property damage and liability claims for these operations, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon’s and Generation’s future financial conditions and their results of operations and cash flows. For information regarding property insurance, see ITEM 2. PROPERTIES — ExelonGeneration.
Contracted Generation Company, LLC.
Long-Term Power Purchase Contracts
In addition to energy produced by owned generation assets, Generation sources electricity from plants it does not own under long-term contracts. The following tables summarize Generation’s long-term contracts to purchase unit-specific physical power with an original term in excess of one year in duration, by region, in effect as of December 31, 2018:2020:
| | | | | | | | | | | | | | | | | | | | |
| Region | | Number of
Agreements | | Expiration
Dates | | Capacity (MW) |
Mid-Atlantic | | 8 | | | 2021 - 2032 | | 183 | |
| Midwest | | 3 | | | 2021 - 2032 | | 351 | |
| | | | | | |
| ERCOT | | 5 | | | 2021 - 2035 | | 864 | |
| Other Power Regions | | 17 | | | 2021 - 2032 | | 2,568 | |
| Total | | 33 | | | | | 3,966 | |
|
| | | | | | | | |
| Region | | Number of Agreements | | Expiration Dates | | Capacity (MW) |
Mid-Atlantic | | 14 |
| | 2019 - 2032 | | 237 |
|
| Midwest | | 4 |
| | 2019 - 2026 | | 834 |
|
| New England | | 7 |
| | 2019 - 2021 | | 40 |
|
| ERCOT | | 5 |
| | 2020 - 2031 | | 1,524 |
|
| Other Power Regions | | 11 |
| | 2019 - 2030 | | 2,549 |
|
| Total | | 41 |
| | | | 5,184 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | | Total |
| Capacity Expiring (MW) | | 673 |
| | 1,020 |
| | 826 |
| | 298 |
| | 167 |
| | 2,200 |
| | 5,184 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2022 | | 2023 | | 2024 | | 2025 | | Thereafter | | Total |
| Capacity Expiring (MW) | | 884 | | | 304 | | | 103 | | | 101 | | | 461 | | | 2,113 | | | 3,966 | |
Fuel
The following table shows sources of electric supply in GWh for 20182020 and 2017:2019:
| | | | | | | | | | | |
| Source of Electric Supply |
| 2020 | | 2019 |
Nuclear(a) | 175,085 | | | 181,326 | |
| Purchases — non-trading portfolio | 79,972 | | | 70,939 | |
| Fossil (primarily natural gas and oil) | 19,501 | | | 21,554 | |
Renewable(b) | 7,052 | | | 7,777 | |
| Total supply | 281,610 | | | 281,596 | |
|
| | | | | |
| | Source of Electric Supply |
| | 2018 | | 2017 |
Nuclear(a) | 185,020 |
| | 182,843 |
|
| Purchases — non-trading portfolio | 59,154 |
| | 51,595 |
|
| Fossil (primarily natural gas and oil) | 21,015 |
| | 22,546 |
|
Renewable(b) | 8,469 |
| | 7,848 |
|
| Total supply | 273,658 |
|
| 264,832 |
|
__________
| |
(a) | (a)Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g., CENG). Nuclear generation for 2018 and 2017 includes physical volumes of 35,100 GWh and 34,761 GWh, respectively, for CENG. |
| |
(b) | Includes wind, hydroelectric, solar and biomass generating assets. |
The fuel costs per MWh for nuclear generation are less than those2020 and 2019 includes physical volumes of 35,052 GWh and 35,745 GWh, respectively, for fossil-fuel generation. Consequently, nuclear generation is generally the most cost-effective way for Generation to meet its wholesaleCENG.
(b)Includes wind, hydroelectric, solar, and retail load servicing requirements.biomass generating assets.
The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride, and the fabrication of fuel assemblies. Generation has inventory in various forms and does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment, or fabrication services to meet the nuclear fuel requirements of its nuclear units.
Natural gas is procured through long-term and short-term contracts, as well as spot-market purchases. Fuel oil inventories are managed so that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing.
Generation uses financial instruments to mitigate price risk associated with certain commodity price exposures, using both over-the-counter and exchange-traded instruments. See ITEM 1A. RISK FACTORS, ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Critical Accounting Policies and Estimates and Note 1216 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative financial instruments.
Power Marketing
Generation’s integrated business operations include physical delivery and marketing of power. Generation largely obtains physical power supply from its generating assetsowned and power purchase agreementscontracted generation in multiple geographic regions. Power purchase agreements, including tolling arrangements, are commitments related to power generation of specific generation plants and/or dispatch similar to an owned asset depending on the type of underlying asset. The commodity risks associated with the output from generating assetsowned and PPAs arecontracted generation is managed using various commodity transactions including sales to customers. The main objective is to obtain low-cost energy supply to meet physical delivery obligations to both wholesale and retail customers. Generation sells electricity, natural gas, and other energy related products and solutions to various customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in competitive markets. Where necessary, Generation may also purchase transmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs.
Price and Supply Risk Management
Generation also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities. Generation implements a three-year ratable sales plan to align its hedging strategy with its financial objectives. Generation may also enter into transactions that are outside of this ratable sales plan. Generation is exposed to commodity price risk in 20192021 and beyond for portions of its electricity portfolio
that are unhedged. As of December 31, 2018,2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 89%-92%, 56%-59% and 32%-35%94%-97% for 2019, 2020, and 2021, respectively.2021. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilitiesgeneration based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts, including sales to ComEd, PECO, BGE, Pepco, DPL and ACEthe Utility Registrants to serve their retail load. A portion of Generation’s hedging strategy may be implemented through the use of fuel products based on assumed correlations between power and fuel prices. The risk management group and Exelon’s RMC monitor the financial risks of the wholesale and retail power marketing activities. Generation also uses financial and commodity contracts for proprietary trading purposes, but this activity accounts for only a small portion of Generation’s efforts. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.
Capital Expenditures
Generation’s business is capital intensive and requires significant investments primarily in nuclear fuel and energy generation assets. Generation’s estimated capital expenditures for 2019 are approximately $2.0 billion, which includes2021 include Generation's share of the investment in the co-owned Salem plant and the total capital expenditures for the fully consolidated CENG nuclear plants.CENG. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources, for additional information regarding projected 2021 capital expenditures.
Utility Registrants
Merger with Pepco Holdings, Inc.
On March 23, 2016, Exelon completed the merger among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub), and PHI. As a result of that merger, Merger Sub was merged into PHI (the PHI merger) with PHI surviving as a wholly owned subsidiary of Exelon and EEDC, a wholly owned subsidiary of Exelon which also owns Exelon's interests in ComEd, PECO, and BGE (through a special purpose subsidiary in the case of BGE). Following the completion of the PHI merger, Exelon, and PHI completed a series of internal corporate organization restructuring transactions resulting in the transfer of PHI’s unregulated business interests to Exelon and Generation and the transfer of PHI, Pepco, DPL, and ACE to a special purpose subsidiary of EEDC.
Utility Operations
Service Territories and Franchise Agreements
The following table presents the size of service territories, populations of each service territory and the number of customers within each service territory for the Utility Registrants as of December 31, 2018:2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
| Service Territories (in square miles) |
| Electric | | 11,400 | | | 2,100 | | | 2,300 | | | 640 | | | 5,400 | | | 2,800 | |
| Natural Gas | | N/A | | 1,960 | | | 3,050 | | | N/A | | 270 | | | N/A |
| Total | | 11,400 | | | 2,100 | | | 3,250 | | | 640 | | | 5,400 | | | 2,800 | |
| | | | | | | | | | | | |
| Service Territory Population (in millions) |
| Electric | | 9.6 | | | 4.0 | | | 3.0 | | | 2.4 | | | 1.5 | | | 1.1 | |
| Natural Gas | | N/A | | 2.5 | | | 2.9 | | | N/A | | 0.6 | | | N/A |
| Total | | 9.6 | | | 4.0 | | | 3.1 | | | 2.4 | | | 1.5 | | | 1.1 | |
| Main City | | Chicago | | Philadelphia | | Baltimore | | District of Columbia | | Wilmington | | Atlantic City |
| Main City Population | | 2.7 | | | 1.6 | | | 0.6 | | | 0.7 | | | 0.1 | | | 0.1 | |
| | | | | | | | | | | | |
| Number of Customers (in millions) |
| Electric | | 4.1 | | | 1.7 | | | 1.3 | | | 0.9 | | | 0.5 | | | 0.6 | |
| Natural Gas | | N/A | | 0.5 | | | 0.7 | | | N/A | | 0.1 | | | N/A |
| Total | | 4.1 | | | 1.7 | | | 1.3 | | | 0.9 | | | 0.5 | | | 0.6 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Service Territories | | Service Territory Population | | Number of Customers |
| | (in square miles) | | (in millions) | | (in millions) |
| | Total | | Electric | | Natural gas | | Total | | Electric | | Natural gas | | Total | | Electric | | Natural gas |
| ComEd | 11,400 |
| | 11,400 |
| | n/a |
| | 9.5 |
| (a) | 9.5 |
| | n/a |
| | 4.0 |
| | 4.0 |
| | n/a |
|
| PECO | 2,100 |
| | 1,900 |
| | 1,900 |
| | 4.0 |
| (b) | 4.0 |
| | 2.5 |
| | 1.7 |
| | 1.6 |
| | 0.5 |
|
| BGE | 3,250 |
| | 2,300 |
| | 3,050 |
| | 3.1 |
| (c) | 3.0 |
| | 2.9 |
| | 1.3 |
| | 1.3 |
| | 0.7 |
|
| Pepco | 640 |
| | 640 |
| | n/a |
| | 2.4 |
| (d) | 2.4 |
| | n/a |
| | 0.9 |
| | 0.9 |
| | n/a |
|
| DPL | 5,400 |
| | 5,400 |
| | 275 |
| | 1.4 |
| (e) | 1.4 |
| | 0.6 |
| | 0.5 |
| | 0.5 |
| | 0.1 |
|
| ACE | 2,800 |
| | 2,800 |
| | n/a |
| | 1.1 |
| (f) | 1.1 |
| | n/a |
| | 0.6 |
| | 0.6 |
| | n/a |
|
__________
| |
(a) | Includes approximately 2.7 million in the city of Chicago. |
| |
(b) | Includes approximately 1.6 million in the city of Philadelphia. |
| |
(c) | Includes approximately 0.6 million in the city of Baltimore. |
| |
(d) | Includes approximately 0.7 million in the District of Columbia. |
| |
(e) | Includes approximately 0.1 million in the city of Wilmington. |
| |
(f) | Includes approximately 0.1 million in the city of Atlantic City. |
The Utility Registrants have the necessary authorizations to perform their current business of providing regulated electric and natural gas distribution services in the various municipalities and territories in which they now supply such services. These authorizations include charters, franchises, permits, and certificates of public convenience issued by local and state governments and state utility commissions. ComEd's, BGE's (gas), Pepco DC's, and ACE's rights are generally non-exclusive;non-exclusive while PECO's, BGE's (electric) Pepco's, Pepco MD's, and DPL's rights are generally exclusive. Certain authorizations are perpetual while others have varying expiration dates. The Utility Registrants anticipate working with the appropriate governmental bodies to extend or replace the authorizations prior to their expirations.
Utility Regulations
State utility commissions regulate the Utility Registrants' electric and gas distribution rates and service, issuances of certain securities, and certain other aspects of the business. The following table outlines the state commissions responsible for utility oversight.
|
| | | | | | | |
| Registrant | | Commission |
| ComEd | | ICC |
| PECO | | PAPUC |
| BGE | | MDPSC |
| Pepco | | DCPSC/MDPSC |
| DPL | | DPSC/MDPSC |
| ACE | | NJBPU |
The Utility Registrants are public utilities under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of the utilities' business. The U.S. Department of Transportation also regulates pipeline safety and other areas of gas operations for PECO, BGE, and DPL. Additionally, the Utility Registrants are subject to NERC mandatory reliability standards, which protect the nation's bulk power system against potential disruptions from cyber and physical security breaches.
Seasonality Impacts on Delivery Volumes
The Utility Registrants' electric distribution volumes are generally higher during the summer and winter months when temperature extremes create demand for either summer cooling or winter heating. For PECO, BGE, and DPL, natural gas distribution volumes are generally higher during the winter months when cold temperatures create demand for winter heating.
ComEd, BGE, Pepco, and DPL Maryland have electric distribution decoupling mechanisms and BGE has a natural gas decoupling mechanism that eliminate the favorable and unfavorable impacts of weather and customer usage patterns on electric distribution and natural gas delivery volumes. As a result, ComEd’s, BGE’s, Pepco’sComEd's, BGE's, Pepco's, and DPL’sDPL's Maryland electric distribution revenues and BGE's natural gas distribution revenues are not materially impacted by delivery volumes. PECO’sPECO's and DPL's Delaware electric distribution revenues and natural gas distribution revenues and ACE’sACE's electric distribution revenues and DPL’s Delaware electric distribution and natural gas revenues are impacted by delivery volumes.
Electric and Natural Gas Distribution Services
The Utility Registrants are allowed to recover reasonable costs and fair and prudent capital expenditures associated with electric and natural gas distribution services and earn a return on those capital expenditures, subject to commission approval. ComEd recovers costs through a performance-based rate formula. ComEd is required to file an update to the performance-based rate formula on an annual basis. PECO's, BGE’sBGE's, and DPL's electric and gas distribution costs and Pepco's and ACE's electric distribution costs arehave generally been recovered through traditional rate case proceedings. However, the MDPSC and the DCPSC allow utilities to file multi-year rate plans. In certain instances, the Utility Registrants use specific recovery mechanisms as approved by their respective regulatory agencies.
ComEd, Pepco, and ACE customers have the choice to purchase electricity, and PECO, BGE, and DPL customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. The Utility Registrants remain the distribution service providers for all customers and are obligated to deliver electricity and natural gas to customers in their respective service territories while charging a regulated rate for distribution service. In addition, the Utility Registrants also retain significant default service obligations to provide electricity to certain groups of customers in their respective service areas who do not choose a competitive electric generation supplier. PECO and BGE also retain significant default service obligations to provide natural gas to certain groups of customers in their respective service areas who do not choose a competitive natural gas supplier. For natural gas, DPL does not retain default service obligations.obligations for its residential customers.
For customers that choose to purchase electric generation or natural gas from competitive suppliers, the Utility Registrants act as the billing agent and therefore do not record Operating revenues or Purchased power and fuel
expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from a Utility Registrant, the Utility Registrants are permitted to recover the electricity and natural gas procurement costs without mark-up and therefore record equal and offsetting amounts of Operating revenues and Purchased power and fuel expense related to the electricity and/or natural gas. As a result, fluctuations in electricity or natural gas sales and procurement costs have no impact on the Utility Registrants’ Revenues net of purchased power and fuel expense, which is a non-GAAP measure used to evaluate operational performance, or Net Income.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Results of Operations and Note 43 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding electric and natural gas distribution services.
Procurement-Related ProceedingsProcurement of Electricity and Natural Gas
The Utility Registrants' electric supply for its customers is primarily procured through contracts as required by the ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU.their respective state commissions. The Utility Registrants procure electricity supply from various approved bidders, including Generation. RTO spot market purchases and sales are utilized to balance the utility electric load and supply as required. Charges incurred for electric supply procured through contracts with Generation are included in Purchased power from affiliates on the Utility Registrants' Statements of Operations and Comprehensive Income.
PECO's, BGE’s, and DPL's natural gas supplies are purchased from a number of suppliers for terms of up to three years. PECO, BGE, and DPL have annual firm supply and transportation contracts of 132,000 mmcf, 128,000264,000 mmcf and 58,00061,000 mmcf, respectively. In addition, to supplement gas supply at times of heavy winter demands and in the event of temporary emergencies, PECO, BGE, and DPL have available storage capacity from the following sources:
| | | | | | | | | | | | | | | | | |
| Peak Natural Gas Sources (in mmcf) |
| LNG Facility | | Propane-Air Plant | | Underground Storage Service Agreements (a) |
| PECO | 1,200 | | | 150 | | | 19,400 | |
| BGE | 1,056 | | | 550 | | | 22,000 | |
| DPL | 250 | | | N/A | | 3,900 | |
|
| | | | | | | | |
| | Peak Natural Gas Sources (in mmcf) |
| | Liquefied Natural Gas Facility | | Propane-Air Plant | | Underground Storage Service Agreements (a) |
| PECO | 1,200 |
| | 150 |
| | 18,000 |
|
| BGE | 1,056 |
| | 550 |
| | 22,000 |
|
| DPL | 257 |
| | n/a |
| | 3,800 |
|
___________(a)Natural gas from underground storage represents approximately 28%, 20%, and 33% of PECO's, BGE’s, and DPL's 2020-2021 heating season planned supplies, respectively.
| |
(a) | Natural gas from underground storage represents approximately 28%, 54% and 34% of PECO's, BGE’s and DPL's 2018-2019 heating season planned supplies, respectively. |
PECO, BGE, and DPL have long-term interstate pipeline contracts and also participate in the interstate markets by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Earnings from these activities are shared between the utilities and customers. PECO, BGE, and DPL make these sales as part of a program to balance its supply and cost of natural gas. The off-system gas sales are not material to PECO, BGE, and DPL.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, Commodity Price Risk (All Registrants), for additional information regarding Utility Registrants' contracts to procure electric supply and natural gas.
Energy Efficiency Programs
The Utility Registrants are generally allowed to recover costs associated with the energy efficiency and demand response programs.programs they offer. Each commission approved program seeks to meet mandated electric consumption reduction targets and implement demand response measures to reduce peak demand. The programs are designed to meet standards required by each respective regulatory agency.
The Utility Registrants areComEd is allowed to earn a return on theirits energy efficiency costs. See Note 43 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Capital Investment
The Utility Registrants' businesses are capital intensive and require significant investments, primarily in electric transmission and distribution and natural gas transportation and distribution facilities, to ensure the adequate capacity, reliability, and efficiency of their systems. ComEd's, PECO's, BGE's, Pepco's, DPL'sSee ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and ACE's most recent estimates ofCapital Resources, for additional information regarding projected 2021 capital expenditures for plant additions and improvements for 2019 are as follows:
|
| | | | | | | | | | | |
| | Projected 2019 Capital Expenditure Spending |
| (in millions) | Transmission | | Distribution | | Gas | | Total |
| ComEd | 325 |
| | 1,550 |
| | N/A |
| | 1,875 |
|
| PECO | 125 |
| | 600 |
| | 250 |
| | 975 |
|
| BGE | 225 |
| | 475 |
| | 400 |
| | 1,100 |
|
| Pepco | 75 |
| | 650 |
| | N/A |
| | 725 |
|
| DPL | 100 |
| | 200 |
| | 50 |
| | 350 |
|
| ACE | 150 |
| | 150 |
| | N/A |
| | 300 |
|
Transmission Services
Under FERC’s open access transmission policy, the Utility Registrants, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants and their affiliates are required to comply with FERC’s Standards of Conduct regulation governing the communication of non-public transmission information between the transmission owner’s employees and wholesale merchant employees.
PJM is the regional grid operator and operates pursuant to FERC-approved tariffs. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff). PJM operates the PJM energy, capacity, and other markets, and, through central dispatch, controls the day-to-day operations of the bulk power system for the region. The Utility Registrants are members of PJM and provide regional transmission service pursuant to the PJM Tariff. The Utility Registrants and the other transmission owners in PJM have turned over control of certain of their transmission facilities to PJM, and their transmission systems are under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a region-wide, open-accessopen-
access basis using the transmission facilities of the PJM transmission owners at rates based on the costs of transmission service.
ComEd'sThe Utility Registrants' transmission rates are established based on a formula that was initially approved by FERC in January 2008. BGE's, Pepco's, DPL's and ACE's transmission rates are established based on a formula that was approved by FERC in April 2006. FERC’s orders establish the agreed-upon treatment of costs and revenues in the determination of transmission rates and the process for updating the formula rate calculation on an annual basis.as shown below:
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rate and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The new formula was accepted by FERC effective as of December 1, 2017, subject to refund and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge.
See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the PECO transmission formula rate and transmission services.
Employees
As of December 31, 2018, Exelon and its subsidiaries had 33,383 employees in the following companies, of which 11,372 or 34% were covered by collective bargaining agreements (CBAs):
|
| | | | | | | | | | | | | | |
| | IBEW Local 15(a) | | IBEW Local 614(b) | | Other CBAs | | Total Employees Covered by CBAs | | Total Employees |
Generation(c) | 1,568 |
| | 84 |
| | 2,485 |
| | 4,137 |
| | 14,110 |
|
| ComEd | 3,378 |
| | — |
| | — |
| | 3,378 |
| | 6,152 |
|
| PECO | — |
| | 1,381 |
| | — |
| | 1,381 |
| | 2,708 |
|
BGE(d) | — |
| | — |
| | — |
| | — |
| | 3,025 |
|
PHI(e) | — |
| | — |
| | 277 |
| | 277 |
| | 1,258 |
|
Pepco(e) | — |
| | — |
| | 1,023 |
| | 1,023 |
| | 1,423 |
|
DPL(e) | — |
| | — |
| | 684 |
| | 684 |
| | 940 |
|
ACE(e) | — |
| | — |
| | 386 |
| | 386 |
| | 612 |
|
Other(g) | 62 |
| | — |
| | 44 |
| | 106 |
| | 3,155 |
|
| Total | 5,008 |
|
| 1,465 |
|
| 4,899 |
|
| 11,372 |
|
| 33,383 |
|
__________
| | | | | |
(a) | A separate CBA between ComEd and IBEW Local 15 covers approximately 73 employees in ComEd’s System Services Group and will expire in 2020. Generation’s and ComEd’s separate CBAs with IBEW Local 15 will expire in 2022. |
| Approval Date |
(b)ComEd | PECO craft and call center employees in the Philadelphia service territory are covered by CBAs with IBEW Local 614, both expiring in 2021. Additionally, Exelon Power, an operating unit of Generation, has an agreement covering 84 employees, which expires in 2019. |
| January 2008 |
(c)PECO | During 2018, Generation acquired and finalized its CBA with Distrigas Local 369, which will expire in 2020, and additionally, finalized a first collective bargaining agreement, expiring in 2021, with a small unit of employees represented by IUOE Local 501 at Exelon's Hyperion Solutions facility. Also in 2018, Generation finalized a three-year agreement with the Security Officer union at Braidwood and that CBA will expire in 2021. During 2017, Generation finalized CBAs with the Security Officer unions at LaSalle, Limerick and Quad Cities, which all will expire in 2020 and Dresden expiring in 2021. Additionally, during 2017, Generation acquired and combined two CBAs at FitzPatrick into one CBA covering both craft and security employees, which will expire in 2023. During 2016, Generation finalized its CBA with the Security Officer union at Oyster Creek, expiring in 2022 and New Energy IUOE Local 95-95A, which will expire in 2021. Also, during 2016, Generation finalized a 5-year agreement with the New England ENEH, UWUA Local 369, which will expire in 2022. During 2015, Generation finalized its CBA with Clinton Local 51 which will expire in 2020; its two CBAs with Local 369 at Mystic 7 and Mystic 8/9, both expiring in 2020; and three Security Officer unions at Byron, Clinton and TMI, all expiring betweenDecember 2019 and 2021, respectively. During 2014, Generation finalized CBAs with TMI Local 777 and Oyster Creek Local 1289, expiring in 2019 and 2021, respectively. Also in 2014, CENG finalized its CBA with Nine Mile Point which will expire in 2020. |
| |
(d)BGE | In January 2017, an election was held at BGE which resulted in union representation for certain employees, who numbered 1,284 at the end of 2018. BGE and IBEW Local 410 are negotiating an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. No agreement has been finalized to date and management cannot predict the outcome of such negotiations. |
| April 2006 |
(e)Pepco | PHI’s utility subsidiaries are parties to five CBAs with four local unions. CBAs are generally renegotiated every three to five years. All these CBAs were renegotiated in 2014 and were extended through various dates ranging from October 2018 through June 2020. During 2018, ACE finalized a five-year agreement with Local 210, expiring in 2023. |
| April 2006 |
(f)DPL | Other includes shared services employees at BSC.April 2006 |
| ACE | April 2006 |
Employees
The Registrants strive to create a workplace that is diverse, innovative, and safe for their employees. In order to provide the services and products that their customers expect, the Registrants must create the best teams. These teams must reflect the diversity of the communities that the Registrants serve. Therefore, the Registrants strive to attract highly qualified and diverse talent and routinely review their hiring and promotion practices to ensure they maintain equitable and bias free processes to neutralize any unconscious bias. The Registrants provide growth opportunities, competitive compensation and benefits, and a variety of training and development programs. The Registrants are committed to helping employees grow their skills and careers largely through numerous training opportunities in technical, safety and business acumen areas, mentorship programs, and continuous feedback and development discussions and evaluations. Employees are encouraged to thrive outside the workplace as well. The Registrants provide a full suite of wellness benefits targeted at supporting work-life balance, physical, mental and financial health, and industry-leading paid leave policies.
The Registrants conduct an employee engagement survey every other year to help identify their successes and areas where they can grow. The survey results are reviewed with senior management and the Exelon Board of Directors.
Diversity Metrics
The following tables show diversity metrics for all employees and management as of December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Employees | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Female(a) (b) | | 7,993 | | | 2,492 | | | 1,517 | | | 727 | | | 765 | | | 1,281 | | | 366 | | | 154 | | | 121 | |
People of Color(b) | | 9,298 | | | 2,083 | | | 2,432 | | | 890 | | | 1,067 | | | 1,748 | | | 898 | | | 194 | | | 139 | |
| Aged <30 | | 3,268 | | | 1,363 | | | 625 | | | 279 | | | 273 | | | 425 | | | 183 | | | 85 | | | 62 | |
| Aged 30-50 | | 17,119 | | | 6,712 | | | 3,491 | | | 1,292 | | | 1,694 | | | 2,207 | | | 756 | | | 466 | | | 369 | |
| Aged >50 | | 11,953 | | | 4,407 | | | 2,138 | | | 1,227 | | | 1,172 | | | 1,594 | | | 517 | | | 385 | | | 219 | |
Total Employees(c) | | 32,340 | | | 12,482 | | | 6,254 | | | 2,798 | | | 3,139 | | | 4,226 | | | 1,456 | | | 936 | | | 650 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Management(d) | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Female(a) (b) | | 1,175 | | | 299 | | | 209 | | | 112 | | | 112 | | | 177 | | | 46 | | | 14 | | | 19 | |
People of Color(b) | | 1,132 | | | 220 | | | 276 | | | 104 | | | 132 | | | 232 | | | 112 | | | 27 | | | 14 | |
| Aged <30 | | 78 | | | 51 | | | 4 | | | 5 | | | 3 | | | 11 | | | 3 | | | 4 | | | — | |
| Aged 30-50 | | 2,790 | | | 1,220 | | | 441 | | | 137 | | | 238 | | | 341 | | | 102 | | | 59 | | | 47 | |
| Aged >50 | | 2,219 | | | 841 | | | 369 | | | 213 | | | 170 | | | 277 | | | 73 | | | 63 | | | 34 | |
| Within 10 years of retirement eligibility | | 2,936 | | | 1,113 | | | 487 | | | 250 | | | 235 | | | 370 | | | 95 | | | 82 | | | 46 | |
Total Employees in Management(c) | | 5,087 | | | 2,112 | | | 814 | | | 355 | | | 411 | | | 629 | | | 178 | | | 126 | | | 81 | |
__________
(a)The Registrants are devoted to creating an environment that allows women to stay in the workforce, grow with the company, and move up the ranks, all with parity of pay. Exelon employs an independent third-party vendor to run regression analysis on all management positions each year. The analysis consistently shows that the Registrants have no systemic pay equity issues.
(b)This is based on self-disclosed information.
(c)Total employees represents the sum of the aged categories.
(d)Management is defined as executive/senior level officials and managers as well as all employees who have direct reports and supervisory responsibilities.
Turnover Rates
As turnover is inherent, management succession planning is performed and tracked for all executives and critical key manager positions. Management frequently reviews succession planning to ensure the Registrants are prepared when positions become available.
The table below shows the average turnover rate for all employees for the last three years of 2018 to 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Retirement Age | | 4.13 | % | | 4.80 | % | | 3.69 | % | | 2.64 | % | | 3.64 | % | | 4.31 | % | | 4.90 | % | | 3.70 | % | | 3.37 | % |
| Voluntary | | 2.87 | % | | 3.88 | % | | 1.37 | % | | 1.55 | % | | 1.37 | % | | 2.18 | % | | 2.51 | % | | 1.10 | % | | 1.21 | % |
| Non-Voluntary | | 0.97 | % | | 0.86 | % | | 0.61 | % | | 1.15 | % | | 0.97 | % | | 0.94 | % | | 1.78 | % | | 0.25 | % | | 0.63 | % |
Collective Bargaining Agreements
Approximately 37% of Exelon’s employees participate in CBAs. The following table presents employee information, including information about CBAs, as of December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | |
| Total Employees Covered by CBAs | | Number of CBAs | | CBAs New and Renewed in 2020(a) | | Total Employees Under CBAs
New and Renewed
in 2020 |
| Exelon | 11,964 | | | 32 | | | 11 | | | 1,715 | |
| Generation | 3,418 | | | 22 | | | 8 | | | 1,001 | |
| ComEd | 3,476 | | | 2 | | | 1 | | | 71 | |
| PECO | 1,350 | | | 2 | | | — | | | — | |
| BGE | 1,423 | | | 1 | | | — | | | — | |
| PHI | 2,203 | | | 5 | | | 2 | | | 626 | |
| Pepco | 954 | | | 1 | | | — | | | — | |
| DPL | 626 | | | 2 | | | 2 | | | 626 | |
| ACE | 390 | | | 2 | | | — | | | — | |
__________
(a)Does not include CBAs that were extended in 2020 while negotiations are ongoing for renewal.
Environmental Regulation
General
The Registrants are subject to comprehensive and complex environmental legislation regarding environmental matters byand regulation at the federal, government and various state, and local jurisdictions in which they operate their facilities. The Registrants are also subjectlevels, including requirements relating to environmental regulations administered by the EPAclimate change, air and various state and local environmental protection agencies. Federal, state and local regulation includes the authority to regulate air, water andquality, solid and hazardous waste, disposal.and impacts on species and habitats.
The Exelon Board of Directors is responsible for overseeing the management of environmental matters. Exelon has a management team to address environmental compliance and strategy, including the CEO; the Senior Vice
President, Corporate Strategy & Chief Innovation and Sustainability Officer; the Senior Vice President, Competitive Market Policy; and the Director, Safety & Sustainability,Vice President, Corporate Environmental Strategy, as well as senior management of Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE.the Registrants. Performance of those individuals directly involved in environmental compliance and strategy is reviewed and affects compensation as part of the annual individual performance review process. The Exelon Board of Directors has delegated to its Generation Oversight Committee and the Corporate
Governance Committee the authority to oversee Exelon’s compliance with health, environmental, and safety laws and regulations and its strategies and efforts to protect and improve the quality of the environment, including Exelon’s internal climate change and sustainability policies and programs, as discussed in further detail below. The respective Boards of ComEd, PECO, BGE, Pepco, DPL and ACEthe Utility Registrants oversee environmental, health, and safety issues related to these companies.
Climate Change Mitigation
Exelon supports comprehensive federal climate legislation, including a cap-and-trade program for GHG emissions that addresses the urgent need to substantially reduce national GHG emissions while providing appropriate protections for consumers, businesses, and the economy. In the absence of comprehensive federal legislation, Exelon supports EPA moving forward with meaningful regulation of GHG emissions under the Clean Air Act.
The Registrants currently are subject to, and may become subject to additional, federal and/or state legislation and/or regulations addressing GHG emissions. Generation produces electricity predominantly from low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind, and solar PV) and neither owns nor operates any coal-fueled generating assets. Generation’s natural gas and biomass fired generating plants produce GHG emissions, most notably CO2. However, Generation’s owned-asset emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry.
Other GHG emission sources associated with the Utility Registrants include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF6) leakage from electric transmission and distribution operations, refrigerant leakage from chilling and cooling equipment, and fossil fuel combustion in motor vehicles. In addition, PECO, BGE, and DPL distribute natural gas and Generation sells natural gas at retail; and consumers’ use of such natural gas produces GHG emissions.
International Climate Change Agreements. At the international level, the United States is a party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21st session of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015. Under the Agreement, which became effective on November 4, 2016, the parties committed to try to limit the global average temperature increase and to develop national GHG reduction commitments. On November 4, 2020, the United States formally withdrew from the Paris Agreement, retracting its commitment to reduce domestic GHG emissions by 26%-28% by 2025 compared with 2005 levels. However, on January 20, 2021, President Biden accepted the Paris Agreement, which resulted in the United States’ formal re-entry on February 19, 2021. The Biden administration has announced its intent to pursue ambitious GHG reductions in the United States and internationally.
Federal Climate Change Legislation and Regulation. It is highly uncertain whether federal legislation to significantly reduce GHG emissions will be enacted in the near-term. If such legislation were adopted, it would likely increase the value of Exelon's low-carbon fleet even though Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procure emission allowances or credits. Continued inaction could negatively impact the value of Exelon’s low-carbon fleet.
The Clean Power Plan and Affordable Clean Energy Rule.TheEPA’s 2015 Clean Power Plan (CPP) established regulations addressing carbon dioxide emissions from existing fossil-fired power plants under Clean Air Act Section 111(d). The CPP’s carbon pollution limits could be met through changes to the electric generation system, including shifting generation from higher-emitting units to lower- or zero-emitting units, as well as the development of new or expanded zero-emissions generation. In July 2019, the EPA published its final Affordable Clean Energy rule, which repealed the CPP and replaced it with less stringent emissions guidelines for existing fossil-fired power plants based on heat rate improvement measures that could be achieved within the fence line of individual plants. Exelon, together with a coalition of other electric utilities, filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit on September 6, 2019, challenging the Affordable Clean Energy rule as unlawful. This lawsuit was consolidated with separate challenges to the Affordable Clean Energy rule filed by various states, non-governmental organizations, and business coalitions. On January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit held the Affordable Clean Energy Rule to be unlawful, vacated the rule, and remanded it to the EPA. The EPA has indicated it will promulgate new GHG limits for existing power plants in accordance with the U.S. Court of Appeals for the D.C. Circuit's order.
State Climate Change Legislation and Regulation. A number of states in which the Registrants operate have state and regional programs to reduce GHG emissions and renewable and other portfolio standards, which impact the power sector. See discussion below for additional information on renewable and other portfolio standards. As the nation’s largest generator of carbon-free electricity, Generation’s fleet supports these efforts to produce safe, reliable electricity with minimal GHGs.
Eleven northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, Vermont, and Virginia) currently participate in the RGGI, which is in the process of strengthening its requirements. The program requires most fossil fuel-fired power plants in the region to hold allowances, purchased at auction, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold these allowances. In October 2019, the Governor of Pennsylvania issued an Executive Order directing the PA DEP to begin a rulemaking process to allow Pennsylvania to join the RGGI, with the goal of reducing carbon emissions from the electricity sector. On November 7, 2020, the PA DEP proposed its rule.
Broader state programs impact other sectors as well, such as New York’s Climate Leadership and Community Protection Act, which establishes statewide emission limits; and Massachusetts’ Clean Energy and Climate Plan, which aims to reduce GHG emissions across all sectors through increased efficiency in buildings and vehicles, the electrification of vehicles and thermal conditioning in buildings, and the replacement of carbon intensive fuels with renewable energy sources.
While the Registrants cannot predict the nature of future regulations or how such regulations might impact future financial statements, Generation has a low emission portfolio, and GHG restrictions would likely benefit zero- and low-emission generating units relative to higher-emission fossil fuel-fired generating units.
In addition, Exelon facilities and operations are subject to the global impacts of climate change. Exelon believes its operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS for additional information.
Renewable and Clean Energy Standards
Thirty states and the District of Columbia, incorporating the vast majority of states where Exelon operates, have adopted some form of renewable or clean energy procurement requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. The Utility Registrants comply with these various requirements through purchasing qualifying renewables, implementing efficiency programs, acquiring sufficient credits (e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from retail customers the costs of complying with their state RPS requirements, including the procurement of RECs or other alternative energy resources. Illinois, New York, and New Jersey adopted standards targeted at preserving the zero-carbon attributes of certain nuclear-powered generating facilities. Generation owns multiple facilities participating in these programs within these states. Other states in which Exelon operates are considering similar programs.
See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Air Quality
Mercury and Air quality regulations promulgated byToxics Standards (MATS). In 2011, the EPA and the various state and local environmental agencies impose restrictions on emission of particulates, sulfur dioxide (SO2), nitrogen oxides (NOx), mercury and other air pollutants and require permits for operation of emitting sources. Such permits have been obtainedsigned a final rule, known as needed by Exelon’s subsidiaries. However, dueMATS, to its low emitting generation fleet comprised of nuclear, natural gas, hydroelectric, wind and solar, compliance with the Federal Clean Air Act does not have a material impact on Generation’s operations.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information regarding clean air regulation in the forms of the CSAPR, the regulationreduce emissions of hazardous air pollutants from coal-power plants. MATS requires coal-fired power plants to achieve high removal rates of mercury, acid gases, and oil-fired electric generating facilities underother metals, and to make capital investments in pollution control equipment and incur higher operating expenses. In 2016, in response to a Supreme Court decision requiring the EPA to consider costs in determining whether it was appropriate and necessary to regulate power plant emissions of hazardous air pollutants, the EPA issued a supplemental finding that, after considering costs, it remained appropriate and necessary. On May 22, 2020, the EPA reversed course, publishing a final rule revoking the "appropriate and necessary" finding underpinning MATS. A coal mining company filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit seeking vacatur of MATS based on the EPA’s May 22, 2020 finding; on September 11, 2020, the U.S. Court of Appeals for the D.C. Circuit granted a motion by Exelon and two other
entities to intervene in that lawsuit to defend MATS, and regulationon September 28, 2020, the U.S. Court of GHG emissions.Appeals for the D.C. Circuit issued an Executive Order holding this portion of the MATS litigation in abeyance. On July 21, 2020, Exelon and two other entities filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit challenging the EPA’s May 22, 2020 rescission of the appropriate and necessary finding underpinning MATS. This portion of the case is also being held in abeyance in response to the DOJ’s motion filed February 12, 2021. On January 20, 2021, President Biden issued an Executive Order directing the EPA to reconsider its May 22, 2020 recission by August 2021; the EPA will likely re-affirm the finding that it is appropriate and necessary to regulate power plant emissions of hazardous air pollutants. As a result, this litigation is likely to be rendered moot, and MATS will likely remain in place in the interim.
Water Quality
Under the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated, and permits must be renewed periodically. Certain of Exelon's facilities discharge stormwater, and industrial wastewater, and/or cooling water into waterways and are therefore subject to these regulations and operate under NPDES permits or pending applications for renewals of such permits after being granted an administrative extension. Generation is also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage.permits.
Section 316(b) of the Clean Water Act
Section 316(b) is implemented through the NDPES program and requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts and is implemented through state-level NPDES permit programs. All ofimpacts. Generation’s power generation facilities with cooling water intake systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by recent changes to the regulations. For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mystic 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities and Salem.
On October 14, 2014, the EPA'sEPA’s Section 316(b) rule became effective. The rule requires that a seriesregulations finalized in 2014; the regulation’s requirements have been or will be addressed through renewal of studies and analyses be performed to determine the best technology available to minimize adverse impacts on aquatic life, followed by an implementation period for the selected technology. The timing of the various requirements for each facility is related to the status of its currentthese facilities’ NPDES permit and the subsequent renewal period. There is no fixed compliance schedule, as this is left to the discretion of the state permitting director.
permits. Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, Generation cannot estimate the effect that compliance with the EPA’s 2014 rule will have on the operation of its generating facilities and its future results of operations, cash flows, and financial position.statements. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility’s economic viability could be called into question. However, the potential impact of the rule has been significantly reduced since the final rule does not mandate cooling towers as a national standard and sets forth technologies that are presumptively compliant, and theallows state permitting director is requireddirectors to applyrequire alternative, less costly technologies and/or operational measures, based on a cost-benefit test and can take into consideration site-specific factors, such as those that would make cooling towers infeasible.
Pursuant to discussions with the NJDEP in 2010 regarding the application of Section 316(b) to Oyster Creek, Generation agreed to permanently cease generation operations at Oyster Creek before the expiration of its operating license in 2029. On September 17, 2018, Oyster Creek permanently ceased generation operations, and its cooling water intake system is no longer subject to Section 316(b). See Note 8 - Early Plant Retirementsassessment of the Combined Notes to Consolidated Financial Statements for additional information about the salefeasibility, costs, and decommissioningbenefits of Oyster Creek.
New York Facilities
In July 2011, the New York Department of Environmental Conservation (DEC) issued a policy regarding the best available technology for cooling water intake structures. Through its policy, the DEC established closed-cycle cooling or its equivalent as the performance goal for all existing facilities, but also provided that the DEC will select a feasible technology whose costs are not wholly disproportionate to the environmental benefits to be gained and allows for a site-specific determination where the entrainment performance goal cannot be achieved (i.e., the requirement most likely to support cooling towers). The Ginna, Nine Mile Point Unit 1, and Fitzpatrick power generation facilities have received renewals of their state water discharge permits and cooling towers were not required. These facilities are now engaged in the required analyses to enable the environmental agency to determine the best technology available in the next permit renewal cycles.
Salemoptions.
On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers and allows Salem to continue to operate utilizing the existing cooling water system with certain required system modifications. However, the permit is being challenged by an environmental organization, and if successful, could result in additional costs for Clean Water Act compliance. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility.
Under Clean Water Act Section 404 and state laws and regulations, the Registrants may be required to obtain permits for projects involving dredge or fill activities in Waters of the United States.
Where Registrants’ facilities are required to secure a federal license or permit for activities that may result in a discharge to covered waters, they may be required to obtain a state water quality certification under Clean Water Act section 401.
Generation is also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage.
Solid and Hazardous Waste and Environmental Remediation
CERCLA provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances and authorizes the EPA either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of hazardous waste at sites, mostmany of which are listed by the EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight prioroversight. Most states have also enacted statutes that contain provisions substantially similar to listing onCERCLA. Such statutes apply in many states where the NPL. Various states,Registrants currently own or
operate, or previously owned or operated, facilities, including Delaware, Illinois, Maryland, New Jersey, and Pennsylvania and the District of Columbia have also enacted statutes that contain provisions substantially similar to CERCLA.Columbia. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.
Generation, ComEd, PECO, BGE, Pepco, DPLThe Registrants’ operations have in the past, and ACEmay in the future, require substantial expenditures in order to comply with these Federal and state environmental laws. Under these laws, the Registrants may be liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. The Registrants and their subsidiaries are, or could become in the future, parties to proceedings initiated by the EPA, state agencies, and/or other responsible parties under CERCLA and RCRA or similar state laws with respect to a number of sites, including MGP sites or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party.
See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding solid and hazardous waste regulation and legislation.
Environmental Remediation
ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover environmental remediation costs of the MGP sites through a provision within customer rates. BGE, ACE, Pepco, and DPL do not have material contingent liabilities relating to MGP sites. The amount to be expended in 20192021 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is expectedestimated to total $46be approximately $35 million consistingwhich consists primarily of $36 million, $6 million and $4$30 million at ComEd, PECO and BGE respectively. The Utility Registrants also have contingent liabilities forComEd.
environmental remediation of non-MGP contaminants (e.g., PCBs). As of December 31, 2018,2020, the Utility Registrants have established appropriate contingent liabilities for environmental remediation requirements.
The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws.
In addition, Generation, ComEd, PECO, BGE, Pepco, DPL and ACEthe Registrants may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.
See Note 43 — Regulatory Matters and Note 2219 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ environmental matters, remediation efforts, and related impacts to the Registrants’ Consolidated Financial Statements.
Exelon has utility and generation assets, and customers, that are and will be further subject to the impacts
Table of climate change. Accordingly, Exelon is engaged in a variety of initiatives to understand and mitigate these impacts, including investments in resiliency, partnering with federal, state and local governments to minimize impacts, and, importantly, advocating for public policy that reduces emissions that cause climate change. Exelon, as a producer of electricity from predominantly low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind and solar photovoltaic), has a relatively small greenhouse gas (GHG) emission profile, or carbon footprint, compared to other domestic generators of electricity (Exelon neither owns nor operates any coal-fueled generating assets). Exelon's natural gas and biomass fired generating plants produce GHG emissions, most notably, CO2. However, Generation’s owned-asset emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry. As of December 31, 2018, fossil fuel generation represented approximately 29% of Exelon's owned generating capacity, while fossil fuel-fired generation during 2018 represented less than 11% of Exelon's overall generation on a MWh basis. Other GHG emission sources at Exelon include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF6) leakage from electric transmission and distribution operations, refrigerant leakage from chilling and cooling equipment, and fossil fuel combustion in motor vehicles. Exelon facilities and operations are subject to the global impacts of climate change and Exelon believes its operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS for information regarding the market and financial, regulatory and legislative, and operational risks associated with climate change.Contents Climate Change Regulation
Exelon is or may become subject to additional climate change regulation or legislation at the federal, regional and state levels.
International Climate Change Agreements. At the international level, the United States is a Party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21st session of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015, and it became effective on November 4, 2016. Under the Paris Agreement, the Parties agreed to try to limit the global average temperature increase to 2°C (3.6°F) above pre-industrial levels. In doing so, Parties developed their own national reduction commitments. The United States submitted a non-binding target of 17% below 2005 emission levels by 2020 and 26% to 28% below 2005 levels by 2025. President Trump has stated his intention to withdraw the U.S. from the Paris Agreement, but no formal action has been initiated.
Federal Climate Change Legislation and Regulation. It is highly unlikely that federal legislation to reduce GHG emissions will be enacted in the near-term. If such legislation is adopted, it would likely increase the value of Exelon's low-carbon fleet even though Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procure emission allowances or credits. Continued inaction could negatively impact the value of Exelon’s low-carbon fleet.
Under the Obama Administration, the EPA proposed and finalized regulations for fossil fuel-fired power plants, referred to as the Clean Power Plan, which are currently being litigated. Under the Trump Administration, on October
16, 2017 the EPA proposed to repeal the CPP on the basis that the new Administration believed that the CPP rule went beyond the EPA's authority to establish a best system of emissions reduction (BSER) for existing power plants. Subsequently, on August 31, 2018, EPA proposed its Affordable Clean Energy Rule (ACE), which would replace the CPP with revised emission guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants.
Given litigation uncertainty and the absence of a final ACE rule, Exelon and Generation cannot at this time predict the impacts of regulation of existing power plants, or individual state responses to developments related to final resolution of the CPP and ACE regulations, or how developments will impact their future financial statements.
Regional and State Climate Change Legislation and Regulation. A number of states in which Exelon operates have state and regional programs to reduce GHG emissions, including from the power sector. As the nation’s largest generator of carbon-free electricity,Information about our fleet supports these efforts to produce safe, reliable electricity with minimal GHGs. Notably, nine northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont) currently participate in the Regional Greenhouse Gas Initiative (RGGI), which is in the process of strengthening its requirements. The program requires most fossil fuel-fired power plants in the region to hold allowances, purchased at auction, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold these allowances.
Many states in which Exelon subsidiaries operate also have state-specific programs to address GHGs, including from power plants. Most notable of these, besides RGGI, are through renewable and other portfolio standards. Additionally, in response to a court decision clarifying the obligations under the Global Warming Solutions Act, the Massachusetts Department of Environmental Protection in 2017 finalized regulations establishing a statewide cap on CO2 emissions from fossil fuel power plants (Massachusetts remains in RGGI as well). The effect of this new obligation and potential for market illiquidity in the early years represent a risk to Generation’s Massachusetts fossil facilities, including Medway and Mystic. At the same time, the District of Columbia is considering a plan to incorporate the cost of carbon into electricity, via consumption, as well as directly into the cost of transportation and home heating fuels. Details remain to be developed, but the specifics could have implications for Pepco’s operations.
Regardless of whether GHG regulation occurs at the local, state, or federal level, Exelon remains one of the largest, lowest-carbon electric generators in the United States, relying mainly on nuclear, natural gas, hydropower, wind, and solar. The extent that the low-carbon generating fleet will continue to be a competitive advantage for Exelon depends on resolution of the CPP and ACE regulations and associated current or future litigation at the federal level, new or expanded state action on greenhouse gas emissions or direct support of clean energy technologies, including nuclear, as well as potential market reforms that value our fleet’s emission-free attributes.
Renewable and Alternative Energy Portfolio Standards
Thirty-nine states and the District of Columbia, incorporating the vast majority of Exelon operations as well as all utility operations, have adopted some form of RPS requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. Exelon's utilities comply with these various requirements through purchasing qualifying renewables, implementing efficiency programs, acquiring sufficient credits (e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from retail customers the costs of complying with their state RPS requirements, including the procurement of RECs or other alternative energy resources. New York, Illinois and New Jersey adopted standards targeted at preserving the zero-carbon attributes of certain nuclear-powered generating facilities. Generation owns multiple facilities participating in these programs within these states. Other states in which Generation and our utilities operate are considering similar programs.
See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on renewable portfolio standards.
Executive Officers of the Registrants as of February 8, 201924, 2021
Exelon
|
| | | | | | | | | | | | | | | | | | | |
| Name | | Age |
| Position | Position | | Period |
| Crane, Christopher M. | | 6062 |
| | Chief Executive Officer, Exelon; | | 2012 - Present |
| | | | Chairman, ComEd, PECO & BGE | | 2012 - Present |
| | | | Chairman, PHI | | 2016 - Present |
| | | | President, Exelon | | 2008 - Present |
| | | | President, Generation | | 2008 - 2013 |
| | | | | | |
| Cornew, Kenneth W. | | 5355 |
| | Senior Executive Vice President and Chief Commercial Officer, Exelon; | | 2013 - Present |
| | | | President and CEO, Generation | | 2013 - Present |
| | | | Executive Vice President and Chief Commercial Officer, Exelon | | 2012 - 2013 |
| | | | President and Chief Executive Officer, Constellation | | 2012 - 2013 |
| Butler, Calvin G. | | 51 | | | | |
Pramaggiore, Anne R. | | 60 |
| | Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities | | 20182019 - Present |
| | | | Chief Executive Officer, BGE | | 2014 - 2019 |
| | | | | | |
| | | | | | |
| | | | | | |
| Dominguez, Joseph | | 58 | | | Chief Executive Officer, ComEd | | 2012 - 2018 |
| | | | President, ComEd | | 2009 - 2018 |
| | | | | | |
Dominguez, Joseph | | 56 |
| | Chief Executive Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2015 - 2018 |
| | | | Senior Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2012 - 2015 |
| | | | | | |
Innocenzo, Michael A. | | 53 |
| | President and Chief Executive Officer, PECO | | 2018 - Present |
| | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 |
| | | | | | |
Butler, Calvin G. | | 49 |
| | Chief Executive Officer, BGE | | 2014 - Present |
| | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2013 - 2014 |
| | | | Senior Vice President, Corporate Affairs, Exelon | | 2011 - 2013 |
| | | | | | |
Velazquez, David M. | | 59 |
| | President and Chief Executive Officer, PHI | | 2016 - Present |
| | | | President and Chief Executive Officer, Pepco, DPL and ACE | | 2009 - Present |
| | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 |
| | | | | | |
Von Hoene Jr., William A. | | 65 |
| | Senior Executive Vice President and Chief Strategy Officer, Exelon | | 2012 - Present |
| | | | | | |
Nigro, Joseph | | 54 |
| | Senior Executive Vice President and Chief Financial Officer, Exelon | | 2018 - Present |
| | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2013 - 2018 |
| | | | | | |
Aliabadi, Paymon | | 56 |
| | Executive Vice President and Chief Risk Officer, Exelon | | 2013 - Present |
| | | | Managing Director, Gleam Capital Management | | 2012 - 2013 |
| | | | | | |
|
| | | | | | |
| Glockner, David | | 60 | | | Executive Vice President, Compliance and Audit, Exelon | | 2020 - Present |
Name | | Age |
| Chief Compliance Officer, Citadel LLC | Position | | Period2017 - 2020 |
Souza, Fabian E. | | 48 |
| Regional Director, U.S. Securities and Exchange Commission | Senior Vice President and Corporate Controller, Exelon | | 2018 - Present |
| | | | Senior Vice President and Deputy Controller, Exelon | | 2017 - 2018 |
| | | | Vice President, Controller and Chief Accounting Officer, The AES Corporation | | 20152013 - 2017 |
| | | | Vice President, Internal Audit and Advisory Services, The AES Corporation | | 2014 - 2015 |
| | | | Deputy Corporate Controller, The AES Corporation | | 2014 - 2014 |
| | | | Assistant Corporate Controller, Global Controllership, The AES Corporation | | 2013 - 2014 |
| | | | Controller, Global Utilities, The AES Corporation | | 2011 - 2013 |
Generation
|
| | | | | | | |
NameHanson, Bryan C. | | Age55 |
| | Position | | Period |
Cornew, Kenneth W. | | 53 |
| | Senior Executive Vice President and Chief CommercialGeneration Officer, Exelon;Generation | | 20132020 - Present |
| | | | President and CEO, Generation | | 2013 - Present |
| | | | Executive Vice President and Chief Commercial Officer, Exelon | | 2012 - 2013 |
| | | | President and Chief Executive Officer, Constellation | | 2012 - 2013 |
| | | | | | |
Pacilio, Michael J. | | 58 |
| | Executive Vice President and Chief Operating Officer, Exelon Generation | | 2015 - Present |
| | | | President, Exelon Nuclear; Senior Vice President | | 2010 - 2015 |
| | | | and Chief Nuclear Officer, Generation | | |
| | | | | | |
Hanson, Bryan C | | 53 |
| | President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Exelon Generation | | 2015 - Present2020 |
| | | | | | |
McHugh, JamesInnocenzo, Michael A. | | 4755 |
| | Executive Vice President Exelon;and Chief Executive Officer, ConstellationPECO | | 2018 - Present |
| | | | Senior Vice President, Portfolio Management & Strategy, Constellation | | 2016 - 2018 |
| | | | Vice President, Portfolio Management, Constellation | | 2012 - 2016 |
| | | | | | |
Barnes, John | | 55 |
| | Senior Vice President, Generation; President, Exelon Power | | 2018 - Present |
| | | | Senior Vice President, Generation, Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 |
| | | | | | |
| Khouzami, Carim V. | | 45 | | | Chief Executive Officer, BGE | | 2019 - Present |
| | | | Senior Vice President, Chief Operating Officer, Exelon PowerUtilities | | 20122018 - 2019 |
| | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2016 - 2018 |
| | | | Senior Vice President, Chief Integration Officer, Exelon | | 2014 - 2016 |
Wright, Bryan P. | | 52 |
| | | |
| Velazquez, David M. | | 61 | | | President and Chief Executive Officer, PHI | | 2016 - Present |
| | | | President and Chief Executive Officer, Pepco, DPL, and ACE | | 2009 - Present |
| | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 |
| | | | | | |
| Von Hoene Jr., William A. | | 67 | | | Senior Executive Vice President and Chief FinancialStrategy Officer, GenerationExelon | | 20132012 - Present |
| | | | Senior Vice President, Corporate Finance, Exelon | | 2012 - 2013 |
| | | | | | |
Bauer, Matthew N. | | 42 |
| | Vice President and Controller, Generation | | 2016 - Present |
| | | | Vice President and Controller, BGE | | 2014 - 2016 |
| | | | Vice President of Power Finance, Exelon Power | | 2012 - 2014 |
ComEd
|
| | | | | | | | | | | | | | | | | | | |
| Name | | Age |
| Position | Position | | Period |
| | | | | | |
| Nigro, Joseph | | 56 | | | Senior Executive Vice President and Chief Financial Officer, Exelon | | 2018 - Present |
| | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2013 - 2018 |
| | | | | | |
| Souza, Fabian E. | | 50 | | | Senior Vice President and Corporate Controller, Exelon | | 2018 - Present |
| | | | Senior Vice President and Deputy Controller, Exelon | | 2017 - 2018 |
| | | | Vice President, Controller and Chief Accounting Officer, The AES Corporation | | 2015 - 2017 |
Generation
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Crane, Christopher M. | | 62 | | | Principle Executive Officer, Generation | | 2020 - Present |
| | | | Chief Executive Officer, Exelon; | | 2012 - Present |
| | | | President, Exelon | | 2008 - Present |
| | | | | | |
| Cornew, Kenneth W. | | 55 | | | Senior Executive Vice President and Chief Commercial Officer, Exelon; | | 2013 - Present |
| | | | President and Chief Executive Officer, Generation | | 2013 - Present |
| | | | | | |
| | | | | | |
| Swahl, William | | 51 | | | Senior Vice President, Generation; Chief Operating Officer, Exelon Power | | 2021 - Present |
| | | | Vice President, Generation; Vice President, Mid-Atlantic Operations, Exelon Power | | 2014 - 2020 |
| | | | | | |
| Hanson, Bryan C. | | 55 | | | Executive Vice President and Chief Generation Officer, Generation | | 2020 - Present |
| | | | President and Chief Nuclear Officer, Exelon Nuclear, Senior Vice President, Generation | | 2015 - 2020 |
| | | | | | |
| McHugh, James | | 49 | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2018 - Present |
| | | | Senior Vice President, Portfolio Management & Strategy, Constellation | | 2016 - 2018 |
| | | | Vice President, Portfolio Management, Constellation | | 2012 - 2016 |
| | | | | | |
| Rhoades, David | | 54 | | | Senior Vice President, Generation; President and Chief Nuclear Officer, Exelon Nuclear | | 2020 - Present |
| | | | Chief Operating Officer, Fleet Operations, Exelon Nuclear | | 2015 - 2020 |
| | | | | | |
| Wright, Bryan P. | | 54 | | | Senior Vice President and Chief Financial Officer, Generation | | 2013 - Present |
| | | | | | |
| | | | | | |
| | | | | | |
| Bauer, Matthew N. | | 44 | | | Vice President and Controller, Generation | | 2016 - Present |
| | | | Vice President and Controller, BGE | | 2014 - 2016 |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
ComEd
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Dominguez, Joseph | | 5658 |
| | Chief Executive Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2015 - 2018 |
| | | | Senior Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2012 - 2015 |
| | | | | | |
| Donnelly, Terence R. | | 5860 |
| | President and Chief Operating Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President and Chief Operating Officer, ComEd | | 2012 - 2018 |
| | | | | | |
| Jones, Jeanne M. | | 3941 |
| | Senior Vice President, Chief Financial Officer and Treasurer, ComEd | | 2018 - Present |
| | | | Vice President, Finance, Exelon Nuclear | | 2014 - 2018 |
| | | | Director, Finance, Exelon Nuclear | | 2013 - 2014 |
| | | | | | |
| Park, Jane | | 4648 |
| | Senior Vice President, Customer Operations, ComEd | | 2018 - Present |
| | | | | | |
| | | | Vice President, Regulatory Policy & Strategy, ComEd | | 2016 - 2018 |
| | | | Director, Business Strategy & Technology, ComEd | | 2014 - 2016 |
| | | | Chief of Staff to President and Chief Executive Officer, ComEd | | 2012 - 2014 |
| | | | | | |
| Gomez, Veronica | | 4951 |
| | Senior Vice President, Regulatory and Energy Policy and General Counsel, ComEd | | 2017 - Present |
| | | | Vice President and Deputy General Counsel, Litigation, Exelon | | 2012 - 2017 |
| | | | | | |
Marquez Jr., FidelWashington, Melissa | | 5751 |
| | Senior Vice President, Governmental and External Affairs, ComEd | | 20122019 - Present |
| | | | | | |
McGuire, Timothy M. | | 60 |
| Vice President, Governmental and External Affairs, ComEd | | 2019 -2019 |
| | | | Vice President, External Affairs and Large Customer Services, ComEd | | 2016 - 2019 |
| | | | Vice President, Corporate Affairs, Exelon Business Services Company | | 2014 - 2016 |
| | | | | | |
| Perez, David | | 51 | | | Senior Vice President, Distribution Operations, ComEd | | 20162019 - Present |
| | | | Vice President, Transmission and Substations,Substation, ComEd | | 2016 - 2019 |
| | | | Vice President, Regional Operations, ComEd | | 2010 - 2016 |
| | | | | | |
Kozel, Gerald J. | | 46 |
| | Vice President, Controller, ComEd | | 2013 - Present |
| | | | Assistant Corporate Controller, Exelon | | 2012 - 2013 |
PECO
|
| | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Innocenzo, Michael A. | | 5355 |
| | President and Chief Executive Officer, PECO | | 2018 - Present |
| | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 |
| | | | | | |
| McDonald, John | | 6163 |
| | Senior Vice President and Chief Operations Officer, PECO | | 2018 - Present |
| | | | Vice President, Integration, Pepco HoldingsPHI | | 2016 - 2018 |
| | | | Vice President, Technical Services | | 2006 - 2016 |
| Stefani, Robert J. | | 4447 |
| | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2018 - Present |
| | | | Vice President, Corporate Development, Exelon | | 2015 - 2018 |
| | | | Director, Corporate Development, Exelon | | 2012 - 2015 |
| | | | | | |
| Murphy, Elizabeth A. | | 5961 |
| | Senior Vice President, Governmental and External Affairs, PECO | | 2016 - Present |
| | | | Vice President, Governmental and External Affairs, PECO | | 2012 - 2016 |
| | | | | | |
| | | | | | |
| Webster Jr., Richard G. | | 5759 |
| | Vice President, Regulatory Policy and Strategy, PECO | | 2012 - Present |
| | | | | | |
Feldhake, Lauren | | 53 |
| | | |
| Williamson, Olufunmilayo | | 42 | | | Senior Vice President, Customer Operations, PECO | | 2020 - Present |
| | | | Senior Vice President, Chief Commercial Risk Officer, Exelon | | 2017 - Present2020 |
| | | | Director, Customer Care, PECOVice President, Commercial Risk Management, Exelon | | 20142015 - 2017 |
| | | | Director, Customer Financial Operations, PECO | | 2009 - 2014 |
| Gay, Anthony | | 55 | | | | |
Diaz Jr., Romulo L. | | 72 |
| | Vice President and General Counsel, PECO | | 20122019 - Present |
| | | | | | |
Bailey, Scott A. | | 42 |
| | Vice President, Governmental and Controller,External Affairs, PECO | | 20122016 - Present2019 |
| | | | Associate General Counsel, Exelon | | 2010 - 2016 |
| | | | | | |
BGE
|
| | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
Butler, Calvin G.Khouzami, Carim V. | | 4945 |
| | Chief Executive Officer, BGE | | 20142019 - Present |
| | | | Senior Vice President, Regulatory and External Affairs, BGEChief Operating Officer, Exelon Utilities | | 20132018 - 20142019 |
| | | | Senior Vice President, Corporate Affairs,Chief Financial Officer, Exelon Utilities | | 20112016 - 20132018 |
| | | | Senior Vice President, Chief Integration Officer, Exelon | | 2014 - 2016 |
| | | | | | |
| Woerner, Stephen J. | | 5153 |
| | President, BGE | | 2014 - Present |
| | | | Chief Operating Officer, BGE | | 2012 - Present |
| | | | Senior Vice President, BGE | | 2009 - 2014 |
| | | | | | |
| Vahos, David M. | | 4648 |
| | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present |
| | | | Vice President, Chief Financial Officer and Treasurer, BGE | | 2014 - 2016 |
| | | | Vice President and Controller, BGE | | 2012 - 2014 |
| | | | | | |
| Núñez, Alexander G. | | 4749 |
| | Senior Vice President, Regulatory Affairs and Strategy, BGE | | 2020 - Present |
| | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - Present2020 |
| | | | Vice President, Governmental and External Affairs, BGE | | 2013 - 2016 |
| | | | Director, State Affairs, BGE | | 2012 - 2013 |
| | | | | | |
| Case, Mark D. | | 5759 |
| | Vice President, Strategy and Regulatory Affairs, BGE | | 2012 - Present |
| | | | | | |
| | | | | | |
| Oddoye, Rodney | | 4244 |
| | Senior Vice President, Governmental and External Affairs, BGE | | 2020 - Present |
| | | | Vice President, Customer Operations, BGE | | 2018 - Present2020 |
| | | | Director, Northeast Regional Electric Operations, BGE | | 2016 - 2018 |
| | | | Director, Financial Operations, BGE | | 2015 - 2016 |
| | | | Manager, Distribution | | |
| Olivier, Tamla | | 48 | | | Senior Vice President, Customer Operations, BGE | | 20132020 - 2015Present |
| | | | Senior Vice President, Constellation NewEnergy, Inc. | | 2016 - 2020 |
| | | | VP, Human Resources, Exelon Business Services Company | | 2012 - 2016 |
| | | | | | |
| Corse, John | | 5860 |
| | Vice President and General Counsel, BGE | | 2018 - Present |
| | | | Associate General Counsel, Exelon | | 2012 - 2018 |
| | | | | | |
Holmes, Andrew W. | | 50 |
| | Vice President and Controller, BGE | | 2016 - Present |
| | | | Director, Generation Accounting, Exelon | | 2013 - 2016 |
| | | | Director, Derivatives and Technical Accounting, Exelon | | 2008 - 2013 |
PHI, Pepco, DPL, and ACE
|
| | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Velazquez, David M. | | 5961 |
| | President and Chief Executive Officer, PHI | | 2016 - Present |
| | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 |
| | | | President and Chief Executive Officer, Pepco, DPL, and ACE | | 2009 - Present |
| | | | | | |
| Anthony, J. Tyler | | 5456 |
| | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - Present |
| | | | Senior Vice President, Distribution Operations, ComEd | | 2010 - 2016 |
| | | | | | |
| Barnett, Phillip S. | | 5557 |
| | Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL, and ACE | | 2018 - Present |
| | | | Senior Vice President and Chief Financial Officer, PECO | | 2007 - 2018 |
| | | | Treasurer, PECO | | 2012 - 2018 |
| | | | | | |
| Lavinson, Melissa | | 4951 |
| | Senior Vice President, Governmental & External Affairs, PHI, Pepco, DPL, and ACE | | 2018 - Present |
| | | | Vice President, Federal Affairs and Policy and Chief Sustainability Officer, PG&E Corporation | | 2015 - 2018 |
| | | | Vice President, Federal Affairs, PG&E Corporation | | 2012 - 2015 |
| | | | | | |
| Stark, Wendy E. | | 4648 |
| | Senior Vice President, Legal and Regulatory Strategy and General Counsel, PHI, Pepco, DPL, and ACE | | 2019 - Present |
| | | | Vice President and General Counsel, PHI, Pepco, DPL, and ACE | | 2016 - 2018 |
| | | | Deputy General Counsel, Pepco Holdings, Inc. | | 2012 - Present2016 |
| | | | | | |
| McGowan, Kevin M. | | 5759 |
| | Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL, and ACE | | 2016 - Present |
| | | | Vice President, Regulatory Affairs, Pepco Holdings, Inc. | | 2012 - 2016 |
| | | | | | |
Aiken, Robert | | 52 |
| | Vice President and Controller, PHI, Pepco, DPL and ACE | | 2016 - Present |
| | | | Vice President and Controller, Generation | | 2012 - 2016 |
|
| | | | | | |
| Dickens, Derrick | | 56 | | | Senior Vice President, Customer Operations, PHI | | 2020 - Present |
| | | | Vice President, Technical Services, BGE | | 2016 - 2020 |
| | | | Director, Advanced Meter Infrastructure, PECO | | 2012 - 2016 |
| | | | | | |
| Humphrey, Marissa | | 41 | | Vice President, Regulatory Policy and Strategy, PHI, DPL, and ACE | | 2021 - Present |
| | | | Vice President Finance, Exelon Utilities | | 2019 - 2020 |
| | | | Vice President, Finance, PHI | | 2016 - 2019 |
| | | | | | |
Each of the Registrants operates in a complex market and regulatory environment that posesinvolves significant risks, many of which are beyond that Registrant’s direct control. Management of each Registrant regularly meets with the Chief Risk Officer and the Registrant's Risk Management Committee (RMC),Such risks, which comprises officers of the Registrant, to identify and evaluate the most significant risks of the Registrant's business and the appropriate steps to manage and mitigate those risks. The Chief Risk Officer and senior executives of the Registrants discuss those risks with the Finance and Risk Committee and Audit Committee of the Exelon Board of Directors and the ComEd, PECO, BGE and PHI Boards of Directors. In addition, the Generation Oversight Committee of the Exelon Board of Directors evaluates risks related to the generation business. The risk factors discussed below could adverselynegatively affect one or more of the Registrants’ consolidated financial statements, fall primarily under the categories below:
Market and Financial Factors primarily include:
•the marketprice of fuels, in particular the price of natural gas, which affects power prices,
•the generation resources in the markets in which the Registrants operate,
•the demand for electricity, reliability of service, and affordability in the markets where the Registrants conduct their publicly traded securities. Eachbusiness,
•the ability of the Registrants has disclosedto operate their respective generating and transmission and distribution assets, their ability to access capital markets, and the known materialimpacts on their results of operations due to the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19),
•the impacts of on-going competition, and
•emerging technologies and business models, including those related to climate change mitigation and transition to a low carbon economy.
Regulatory, Legislative, and Legal Factors primarily include changes to, and compliance with, the laws and regulations that govern:
•the design of power markets,
•ZEC programs,
•utility regulatory business models,
•environmental and climate policy, and
•tax policy.
Operational Factors primarily include:
•changes in the global climate could produce extreme weather events, which could put the Registrant’s facilities at risk, and such changes could also affect the levels and patterns of demand for energy and related services,
•the safe, secure, and effective operation of Generation’s nuclear facilities and the ability to effectively manage the associated decommissioning obligations,
•the ability of the Registrants to maintain the reliability, resiliency, and safety of their energy delivery systems, which could affect the operating costs of the Registrants and the opinions of their customers and regulators, and
•physical and cyber security risks for the Registrants as the owner-operators of generation, transmission, and distribution facilities and as participants in commodities trading.
Risks Related to the Planned Separation primarily include:
•the timing and conditions associated with required regulatory approvals, which may affect the costs to achieve the separation and its timing,
•challenges to achieving the benefits of separation, including maintaining investment grade credit ratings, and
•the risk that affectthe separation could be treated as a taxable transaction to both Exelon and its business at this time. However, thereshareholders.
There may be further risks and uncertainties that are not presently known or that are not currently believed by a Registrantthe Registrants to be material that could adverselynegatively affect its performance orconsolidated financial conditionstatements in the future.
Exelon's consolidated financial statements are affected to a significant degree by: (1) Generation’s position as a predominantly nuclear generator selling power into competitive energy markets with a concentration in select regions
and (2) the role of the Utility Registrants as operators of electric transmission and distribution systems in six of the largest metropolitan areas in the United States. Factors that affect the consolidated financial statements of the Registrants fall primarily under the following categories, all of which are discussed in further detail below:
Market and Financial Factors. Exelon’s and Generation’s results of operations are affected by price fluctuations in the energy markets. Power prices are a function of supply and demand, which in turn are driven by factors such as (1) the price of fuels, in particular the price of natural gas, which affects the prices that Generation can obtain for the output of its power plants, (2) the presence of other generation resources in the markets in which Generation’s output is sold, (3) the demand for electricity in the markets where the Registrants conduct their business, (4) the impacts of on-going competition in the retail channel and (5) emerging technologies and business models.
Regulatory and Legislative Factors. The regulatory and legislative factors that affect the Registrants include changes to the laws and regulations that govern competitive markets and utility regulatory business model cost recovery, tax policy, zero emission credit programs and environmental policy. In particular, Exelon’s and Generation’s financial performance could be affected by changes in the design of competitive wholesale power markets or Generation’s ability to sell power in those markets. In addition, potential regulation and legislation, including regulation or legislation regarding climate change and renewable portfolio standards (RPS), could have significant effects on the Registrants. Also, returns for the Utility Registrants are influenced significantly by state regulation and regulatory proceedings.
Operational Factors. The Registrants’ operational performance is subject to those factors inherent in running the nation’s largest fleet of nuclear power reactors and large electric and gas distribution systems. The safe, secure and effective operation of the nuclear facilities and the ability to effectively manage the associated decommissioning obligations as well as the ability to maintain the availability, reliability, safety and security of its energy delivery systems are fundamental to Exelon’s ability to achieve value-added growth for customers, communities and shareholders. Additionally, the operating costs of the Registrants and the opinions of their customers, regulators and shareholders are affected by those companies’ ability to maintain the reliability, safety and efficiency of their energy delivery systems.
A discussion of each of these risk categories and other risk factors is included below.
Market and Financial Factors
Generation is exposed to depressed prices inprice volatility associated with both the wholesale and retail power markets which could negatively affect its consolidated financial statementsand the procurement of nuclear and fossil fuel (Exelon and Generation).
Generation is exposed to commodity price risk for the unhedged portion of its electricity generation supply portfolio. Generation’s earnings and cash flows are therefore exposed to variability of spot and forward market prices in the markets in which it operates.
Price of Fuels. The spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the market during that hour. Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit.
Demand and Supply. The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs could each depress demand. In addition, in some markets, the supply of electricity could often exceed demand during some hours of the day, resulting in loss of revenue for base-load generating plants such as Exelon'sGeneration's nuclear plants. Conversely, new demand sources such as electrification of transportation could increase demand and change demand patterns.
Retail Competition. Generation’s retail operations compete for customers in a competitive environment, which affects the margins that Generation can earn and the volumes that it is able to serve. In periods of sustained low natural gas and power prices and low market volatility, retail competitors can aggressively pursue market share because the barriers to entry can be low and wholesale generators (including Generation) use their retail operations to hedge generation output. Increased or more aggressive competition could adversely affect overall gross margins and profitability in Generation’s retail operations.
SustainedThe impact of sustained low market prices or depressed demand and over-supply could adversely affect Exelon’s and Generation’s consolidated financial statements and such impacts could be emphasized given Generation’s concentration of base-load electric generating capacity within primarily two geographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect Exelon’s and Generation’s ability to fund regulated utility growth for the benefit of customers, reduce debt and provide attractive shareholder returns. In addition, such conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Exelon's and Generation's result of operationsfinancial statements primarily through accelerated depreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flight capital projects, accelerated amortization of plant specific nuclear fuel costs, severance costs, accelerated asset retirement obligation expense related to future decommissioning activities,expenses and additional funding of decommissioning costs, which can be offset in whole or in part by reduced operating and maintenance expenses.one-time charges. See Note 87 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
In additionCost of Fuel. Generation depends on nuclear fuel and fossil fuels to operate most of its generating facilities. The supply markets for nuclear fuel, natural gas, and oil are subject to price fluctuations, Generation is exposed to other risks in the power markets that are beyond its controlavailability restrictions, and could negatively affect its results of operations (Exelon and Generation).counterparty default.
Credit Risk. In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money, or are obligated to purchase energy or fuel from Generation, will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent of amounts, if any, already paid to the counterparties. In the spot markets, Generation is exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs, the purpose of which is to spread such risk across all market participants. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, Generation’s retail sales subject it to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer.
Market Designs. The wholesale markets vary from region to region with distinct rules, practices, and procedures. Changes in these market rules, problems with rule implementation, or failure of any of these markets could adversely affect Generation’s business. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect on market stability.
The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry including technologies related to energy generation, distribution and consumption (All Registrants).
Some of these technologies include, but are not limited to, further development or applications of technologies related to shale gas production, renewable energy technologies, energy efficiency, distributed generation, and energy
storage devices. Such developments could affect the price of energy, levels of customer-owned generation, customer expectations, and current business models and make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy. Each of these factors could materially affect the Registrants’ consolidated financial statements through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well asand potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.
Market performance and other factors could decrease the value of NDT funds and employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants).
Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of the investments held within Generation’s NDTs and Exelon’s employee benefit plan trusts. The Registrants have significant obligations in these areas and Exelon and Generation hold substantial assets in these trusts to meet those obligations. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below the Registrants’ projected return rates. A decline in the market value of the NDT fund investments could increase Generation’s funding requirements to
decommission its nuclear plants. A decline in the market value of the pension and OPEB plan assets willwould increase the funding requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the costs and funding requirements of the obligations related to the pension and OPEB plans. If future increases in pensionSee Note 10 — Asset Retirement Obligations and other postretirement costs as a result of reduced plan assets or other factors cannot be recovered, or cannot be recovered in a timely manner, from the Utility Registrants' customers, the consolidated financial statementsNote 15 — Retirement Benefits of the UtilityCombined Notes to Consolidated Financial Statements for additional information.
The Registrants could be negatively affected. Ultimately, if the Registrants are unable to manage the investments within the NDT funds and benefit plan assets and are unable to manage the related benefit plan liabilities and the related asset retirement obligations, their consolidated financial statements could be negatively impacted.
Unstableaffected by unstable capital and credit markets and increased volatility in commodity markets could adversely affect the Registrants’ businesses in several ways, including the availability and cost of short-term funds for liquidity requirements, the Registrants’ ability to meet long-term commitments, Generation’s ability to hedge effectively its generation portfolio, and the competitiveness and liquidity of energy markets; each could negatively impact the Registrants’ consolidated financial statements (All Registrants).
The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs if internal funds are not available from the Registrants’ respective operations.needs. Disruptions in the capital and credit markets in the United States or abroad could adverselynegatively affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The Registrants’ access to funds under their credit facilities depends on the ability of the banks that are parties to the facilities to meet their funding commitments. Those banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from the Registrants and other borrowers within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives, or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, Generation’s ability to hedge effectively its generation portfolio, changes to Generation’s hedging strategy in order to reduce collateral posting requirements, or a reduction in dividend payments or other discretionary uses of cash.
In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2018,2020, approximately 23%, 19%, or $1.8 billion, 19%, or $1.8 billion, and 18%, or $1.7 billion of the Registrants’ available credit facilities were with European, Canadian, and Asian banks, respectively. The credit facilities include $9.7 billion (including bilateral credit facilities and credit facilities for project
finance) in aggregate total commitments of which $8.0 billion was available as of December 31, 2018. As of December 31, 2018, there were no borrowings under Generation's bilateral credit facilities. See Note 1317 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities.
The strength and depth of competition in energy markets depend heavily on active participation by multiple trading parties, which could be adverselynegatively affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that could affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on Exelon’s and Generation’s consolidated financial statements.contracts.
If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties, it would be required to provide significant amounts of collateral under its agreements with counterparties and could experience higher borrowing costs (All Registrants).
Generation’s business is subject to credit quality standards that could require market participants to post collateral for their obligations. If Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating) or otherwise fail to satisfy the credit standards of trading counterparties, it would be required under its hedging arrangements to provide collateral in the form of letters of credit or cash, which could have a material adverse effect upon its liquidity. The amount of collateral required to be provided by Generation at any point in time depends on a variety of factors, including (1) the notional amount of the applicable hedge, (2) the nature of counterparty and related agreements, and (3) changes in power or other commodity prices. In addition, if Generation were downgraded, it could experience higher borrowing costs as a result of the downgrade. Generation could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the power generation industry in general, or Generation in particular, has deteriorated. Changes in ratings methodologies by the credit rating agencies could also have a negative impact on the ratings of Generation.
Generation has project-specific financing arrangements and must meet the requirements of various agreements relating to those financings. Failure to meet those arrangements could give rise to a project-specific financing default which, if not cured or waived, could result in the specific project being required to repay the associated
debt or other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have broad remedies, including rights to foreclose against the project assets and related collateral or to force the Exelon subsidiaries in the project-specific financings to enter into bankruptcy proceedings. The impact of bankruptcy on such arrangements may be a significant assumptioncould result in performingthe impairment assessments of thecertain project assets.
The Utility Registrants' operating agreements with PJM and PECO's, BGE's, and DPL's natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO, BGE, and DPL, with respect to their natural gas supply contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. Given the relationship to forward market prices, contract collateral requirements can be volatile. In addition, ifIf the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade.
A Utility Registrant could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the utility industry in general, or a Utility Registrant in particular, has deteriorated. A Utility Registrant could experience a downgrade if its current regulatory environment becomes less predictable by materially lowering returns for the Utility Registrant or adopting other measures to limit utility rates. Additionally, the ratings for a Utility Registrant could be downgraded if its financial results are weakened from current levels due to weaker operating performance or due to a failure to properly manage its capital structure. In addition, changes in ratings methodologies by the agencies could also have aan adverse negative impact on the ratings of the Utility Registrants.
The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters — Market Conditions and Security Ratings for additional information regarding the potential impacts of credit downgrades on the Registrants’ cash flows.
Generation’s financial performance could be negatively affected by price volatility, availability and other risk factors associated with the procurement of nuclear and fossil fuel (Exelon and Generation).
Generation depends on nuclear fuel and fossil fuels to operate most of its generating facilities. Nuclear fuel is obtained predominantly through long-term uranium supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. Natural gas and oil are procured for generating plants through annual, short-term and spot-market purchases. The supply markets for nuclear fuel, natural gas and oil are subject to price fluctuations, availability restrictions and counterparty default that could negatively affect the consolidated financial statements for Generation.
Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities (Exelon and Generation).
Generation’s asset-based power position as well as its power marketing, fuel procurement, and other commodity trading activities expose Generation to risks of commodity price movements. Generation buys and sells energy and other products and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolio. Generation is exposed to volatility in financial results for unhedged positions as well as the risk of ineffective hedges. Generation attempts to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations could be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its commodity trading activities and risk management decisions could have on its business or consolidated financial statements.
Financial performance and load requirements could be adverselynegatively affected if Generation is unable to effectively manage its power portfolio (Exelon and Generation).
A significant portion of Generation’s power portfolio is used to provide power under procurement contracts with the Utility Registrants and other customers. To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale power markets. To the extent its power portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale power markets. Generation’s financial results could be negatively affected if it is unable to cost-effectively meet the load requirements of its customers, manage its power portfolio or effectively address the changes in the wholesale power markets.
Challenges to tax positions taken by the Registrants as well as tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions, could impact the Registrants’ consolidated financial statements. (All Registrants).
Corporate Tax Reform. On December 22, 2017, President Trump signed into law the TCJA. See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
While the Registrants’ current tax accounting and future expectations are based on management’s present understanding of the provisions under the TCJA, further interpretive guidance of the TCJA’s provisions could result in further adjustments that could have a material impact to the Registrants’ future consolidated financial statements.
The Utility Registrants have made their best estimate regarding the probability and timingimpacts of settlements of net regulatory liabilities established pursuant to the TCJA. However, the amount and timing of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Utility Registrants’ future consolidated financial statements.
Tax reserves. The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Significant Accounting Policies and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Increases in customer rates, includingsignificant economic downturns or increases in the cost of purchased power and increases in natural gas prices for the Utility Registrants, and the impact of economic downturns could lead to greater expense for uncollectible customer balances. Additionally, increased rates, could lead to decreased volumes delivered. Both of these factors could decrease Generation’sdelivered and the Utility Registrants' results from operations, cash flows or financial positionsincreased expense for uncollectible customer balances (All Registrants).
The impacts of significant economic downturns on the Utility Registrants' customers, such as unemployment for residential customers and less demand for products and services provided by commercial and industrial customers, and the related regulatory limitations on residential service terminations, could result in an increase in the number of uncollectible customer balances', which would negatively affectbalances. Further, increases in customer rates, including those related to increases in purchased power and natural gas prices, could result in declines in customer usage and lower revenues for the Utility Registrants' consolidated financial statements. Registrants that do not have decoupling mechanisms.
Generation's customer-facing energy delivery activities face similar economic downturn risks, such as lower volumes sold and increased expense for uncollectible customer balances which could negatively affect Generation's consolidated financial statements. balances.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information of the Registrants’ credit risk.
The Utility Registrants' current procurement plans include purchasing power through contracted suppliers and in the spot market. ComEd’s, PECO’s and ACE's costs of purchased power are charged to customers without a return or profit component. BGE's, Pepco's and DPL's SOS rates charged to customers recover their wholesale power supply costs and include a return component. For PECO and DPL, purchased natural gas costs are charged to customers with no return or profit component. For BGE, purchased natural gas costs are charged to customers using a MBR mechanism that compares the actual cost of gas to a market index. The difference between the actual cost and the market index is shared equally between shareholders and customers. Purchased power and natural gas prices fluctuate based on their relevant supply and demand. Significantly higher rates related to purchased power and natural gasresults could result in declines in customer usage, lower revenues and potentially additional uncollectible accounts expense for the Utility Registrants. In addition, any challengesbe negatively affected by the regulators or the Utility Registrants asimpacts of COVID-19 (All Registrants).
COVID-19 is an evolving situation that could lead to the recoverabilityextended disruption of these costs could have a material adverse effecteconomic activity in the Registrants’ consolidated financial statements. Also,respective markets. COVID-19 could negatively affect the Utility Registrants' cash flowsRegistrants’ ability to operate their respective generating and transmission and distribution assets, their ability to access capital markets, and their results of operations. The Registrants cannot predict the extent of the impacts of COVID-19, which will depend on future developments and which are highly uncertain. See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Executive Overview for additional information.
The Registrants could be adverselynegatively affected by differences between the time period when electricity and natural gas are purchased and the ultimate recovery from customers.
The effectsimpacts of weather could impact the Registrants’ consolidated financial statements (All Registrants).
Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting revenues
at PECO, DPL Delaware, and ACE. Due to revenue decoupling, BGE, Pepco, and DPL Maryland recognize revenues at MDPSC and DCPSC-approved levels per customer, regardless of what actual distribution volumes are for a billing period and are not affected by actual weather with the exception of major storms. Pursuant to the Future Energy Jobs Act (FEJA), beginning in 2017,ComEd’s customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenue.
Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems, and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customer demand. These extreme conditions could have detrimental effects in the Utility Registrants' consolidated financial statements. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant.
Generation’s operations are also affected by weather, which affects demand for electricity as well as operating conditions. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation could require greater resources to meet its contractual commitments. Extreme weather conditions or storms could affect the availability of generation and its transmission, limiting Generation’s ability to source or send power to where it is sold. In addition, drought-like conditions limiting water usage could impact Generation’s ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could have an adverse effect by causingcause Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when markets are weak.
Certain long-livedClimate change projections suggest increases to summer temperature and humidity trends, as well as more erratic precipitation and storm patterns over the long-term in the areas where Registrants have generation, transmission, and distribution assets. The frequency in which weather conditions emerge outside the current expected climate norms could contribute to weather-related impacts discussed above.
Long-lived assets, goodwill, and other assets recorded on the Registrants’ statements of financial position could become impaired which would result in write-offs of the impaired amounts (All Registrants).
Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. In addition, Exelon, ComEd, and GenerationPHI have significant balances related to unamortized energy contracts, as further disclosed in Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements. material goodwill balances.
The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered when evaluating long-lived assetsconsidered.
ComEd and PHI perform an assessment for potential impairment. Anpossible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would require the Registrants tomore likely than not reduce the carrying value of the long-lived asset to fair value through a non-cash charge to expense by the amount of the impairment, and such an impairment could have a material adverse impact in the Registrants’ consolidated financial statements.
As of December 31, 2018, Exelon's $6.7 billion carrying amount of goodwill primarily consists of $2.6 billion at ComEd relating to the acquisition of ComEd in 2000 upon the formation of Exelon and $4.0 billion at PHI primarily resulting from Exelon's acquisition of PHI in the first quarter of 2016. Under GAAP, goodwill remains at its recorded amount unless it is determined to be impaired, which is generally based upon an annual analysis that compares the implied fair value of the goodwill to itsreporting units below their carrying value. If an impairment occurs, the amount of the impaired goodwill will be written-off to expense, which will also reduce equity. The actual timing and amounts of any goodwill impairments will depend on many sensitive, interrelated and uncertain variables. Such an impairment would result in a non-cash charge to expense, which could have a material adverse impact on Exelon's, ComEd's, and PHI's results of operations.
amount. Regulatory actions or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco’s, DPL’s, and ACE’s business, and the fair value of debt, could potentially result in future impairments of Exelon’s, ComEd's, and PHI’s and ComEd’sgoodwill.
An impairment would require the Registrants to reduce the carrying value of the long-lived asset or goodwill which could be material.
to fair value through a non-cash charge to expense by the amount of the impairment. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, Note 68 — Property, Plant, and Equipment, Note 712 — Impairment of Long-Lived Assets and IntangiblesAsset Impairments and Note 1013 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset impairments and goodwill impairments.
Exelon and its subsidiaries at times guarantee the performance of third parties, whichThe Registrants could result inincur substantial costs in the event of non-performance by such third parties. In addition,third-parties under indemnification agreements, or when the Registrants could have rights under agreements which obligate third partiesguaranteed their performance. Generation is exposed to indemnify the Registrants for various obligations, and the Registrants could incur substantial costsother credit risks in the eventpower markets that the applicable Registrant is unable to enforce those agreements or the applicable third-party is otherwise unable to perform. The Registrants could also incur substantial costs in the event that third parties are entitled to indemnification related to environmental or other risks in connection with the acquisition and divestiture of assetsbeyond its control (All Registrants).
Some of the Registrants have issued guarantees of the performance of third parties, which obligate the Registrant or its subsidiaries to perform in the event that the third parties do not perform. In the event of non-performance by those third parties, a Registrant could incur substantial cost to fulfill its obligations under these guarantees. Such performance guarantees could have a material impact in the consolidated financial statements of the Registrant. Some of the Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets and a Registrant could incur substantial costs to fulfill its obligations under these indemnities and such costs could adversely affect a Registrant’s consolidated financial statements.
Some of theThe Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations, which could adversely impact that Registrant’s consolidated financial statements.obligations. Each of the Utility Registrants has transferred its former generation business to a third party and in each case the transferee may havehas agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO, and BGE transferred their generating assets to Generation, Generation assumed certain of ComEd’s, PECO’s, and BGE's rights and obligations with respect to their former generation businesses. Further, ComEd, PECO, and BGE may have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO, or BGE for certain obligations related to their respective former generation businesses that have been assumed by Generation as part of the restructuring. If the third-party, Generation, or the transferee of Pepco's, DPL's, or ACE’s generation facilities experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims, which could impact that Utility Registrant's consolidated financial statements.claims. In addition, the Utility Registrants may have residual liability under certain laws in connection with their former generation facilities.
The Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets and they could incur substantial costs to fulfill their obligations under these indemnities.
The Registrants have issued guarantees of the performance of third parties, which obligate the Registrants to perform in the event that the third parties do not perform. In the event of non-performance by those third parties, the Registrants could incur substantial cost to fulfill their obligations under these guarantees.
In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money or are obligated to purchase energy or fuel from Generation, will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent amounts, if any, were already paid to the counterparties. In the spot markets, Generation is
exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, Generation’s retail sales subject it to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer.
Regulatory, Legislative, and LegislativeLegal Factors
Federal or state legislative or regulatory actions could negatively affect the scope and functioning of the wholesale markets (Exelon and Generation).
Approximately 70% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the area encompassed by PJM. Generation’s future results of operations are impacted by (1) FERC’s and PJM's support for policies that favor the preservation of competitive wholesale power markets and recognize the value of zero-carbon electricity and resiliency and for states' energy objectives and policies (2) the absence of material changes to market structures that would limit or otherwise negatively affect Exelon or Generation. Generation could also be affected by state laws, regulations, or initiatives to subsidize existing or new generation.
FERC’s requirements for market-based rate authority could pose a risk that Generation may no longer satisfy FERC’s tests for market-based rates.
The Registrants’ generation and energy delivery businesses are highly regulated and could be subject tonegatively affected by regulatory and legislative actions that adversely affect their consolidated financial statements. Fundamental changes in regulation or legislation or violation of tariffs or market rules and anti-manipulation laws, could disrupt the Registrants’ business plans and adversely affect their operations, cash flows or financial results (All Registrants).
Substantially all aspects of the businesses of the Registrants are subject to comprehensive Federal or state regulation and legislation. Further, Exelon’s and
Generation’s consolidated financial statements are significantly affected by Generation'sits sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated rates and Exelon’sFederal and state regulatory and legislative developments related to emissions, climate change, capacity market mitigation, energy price information, resilience, fuel diversity, and RPS. Legislative and regulatory efforts in Illinois, New York, and New Jersey to preserve the environmental attributes and reliability benefits of zero-emission nuclear-powered generating facilities through ZEC programs are or could be subject to legal and regulatory challenges and, if overturned, could result in the early retirement of certain of Generation’s nuclear plants. See Note 3 — Regulatory Matters and Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs for the retail purchase and distribution of power and natural gas to their customers. Similarly, there is risk that financial market regulations could increase the Registrants’ compliance costs and limit their ability to engage in certain transactions. In the planning and management of operations, the Registrants must address the effects of regulation on their businesses and changes in the regulatory framework, including initiatives by Federal and state legislatures, RTOs, exchanges, ratemaking agencies and taxing authorities. Additionally, the Registrants need to be cognizant and understand rule changes or Registrant actions that could result in potential violation of tariffs, market rules and anti-manipulation laws.
Fundamental changes in regulations or other adverse legislative actions affecting the Registrants’ businesses would require changes in their business planning models and operations and could negatively impact their respective consolidated financial statements.
State and federal regulatory and legislative developments related to emissions, climate change, tax reform, capacity market mitigation, energy price information, resilience, fuel diversity and RPS could also significantly affect Exelon’s and Generation’s consolidated financial statements.operations. The Registrants cannot predict when or whether legislative and regulatory proposals could become law or what their effect will be on the Registrants.
LegislativeChanges in the Utility Registrants' respective terms and regulatory efforts in Illinois, New York and New Jersey to preserve the environmental attributes and reliability benefitsconditions of zero-emission nuclear-powered generating facilities through zero emission credit programsservice, including their respective rates, are subject to legal challengesregulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy, and if overturned,subject to appeal, which lead to uncertainty as to the ultimate result and which could introduce time delays in effectuating rate changes (Exelon and the Utility Registrants).
The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of
energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, credit losses, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs. In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives, or franchise agreements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants to recover their costs or earn an adequate return. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.
NRC actions could negatively impact Exelon’saffect the operations and Generation’s consolidated financial statements and result in the early retirement of certainprofitability of Generation’s nuclear plants.generating fleet (Exelon and Generation).
Regulatory risk. A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or could result in increased operating or decommissioning costs. Events at nuclear plants owned by others, as well as those owned by Generation, could cause the NRC to initiate such actions.
Spent nuclear fuel storage. The approval of a national repository for the storage of SNF and the timing of such a facility opening, will significantly affect the costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse Generation for these costs.
Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect Generation’s ability to fully decommission its nuclear units. Generation cannot predict what, if any, fee may be established in the future for SNF disposal. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the SNF obligation.
The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of PJM’s RTEP and NERC compliance requirements (All Registrants).
The Registrants as users, owners, and operators of the bulk power transmission system, including Generation and the Utility Registrants, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. PECO, BGE, and DPL, as operators of natural gas distribution systems, are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DPSC, and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Registrants were found not to be in compliance with the Federal and state mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants).
The businesses that the Registrants operate are subject to extensive environmental regulation and legislation by local, state, and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions, hazardous and solid waste, and activities affecting surface waters, groundwater, and aquatic and other species. Violations of these requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages, or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property
contaminated by hazardous substances they generated or released. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future. See ITEM 1. BUSINESS — Environmental Regulation for additional information.
The Registrants could be negatively affected by possible Federal or state legislative or regulatory actions that could affectchallenges to tax positions taken, tax law changes, and the scopeinherent difficulty in quantifying potential tax effects of business decisions. (All Registrants).
The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and functioning of the wholesale markets (Exelonuse, and Generation).
Approximately 63% of Generation’s generating resources, whichemployment-related taxes and ongoing appeal issues related to these tax matters. These judgments include directly owned assets and capacity obtained through long-term contracts, are located in the area encompassed by PJM. Generation’s future results of operations will depend on (1) FERC’s continued adherence to and supportreserves established for policies that favor the preservation of competitive wholesale power markets and recognize the value of zero-carbon electricity and resiliency and (2) the absence of material changes to market structures that would limit or otherwise negatively affect market competition. Generation could also be adversely affected by state laws, regulations or initiatives designed to reduce wholesale prices artificially below competitive levels or to subsidize existing or new generation.
FERC’s requirements for market-based rate authority, established in Order 697 and 816 and related subsequent orders, could pose a risk that Generation may no longer satisfy FERC’s tests for market-based rates. Since Order 697 became final in June 2007, Generation has obtained orders affirming Generation’s authority to sell at market-based rates and none denying that authority.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was enacted in July 2010. The part of the Act that affects Exelon most significantly is Title VII, which is known as the Dodd-Frank Wall Street Transparency and Accountability Act (Dodd-Frank). Dodd-Frank requires a new regulatory regime for over-the-counter swaps (swaps), including mandatory clearing for certain categories of swaps, incentives to shift swap activity to exchange trading, margin and capital requirements, and other obligations designed to promote transparency. The primary aim of Dodd-Frank is to regulate the key intermediaries in the swaps market, which entities are swap dealers (SDs), major swap participants (MSPs), or certain other financial entities, but the law also applies to a lesser degree to end-users of swaps. The CFTC’s Dodd-Frank regulations generally preserved the ability of end users in the energy industry to hedge their risks using swaps without being subject to mandatory clearing, and many of the other substantive regulations that apply to SDs, MSPs, and other financial entities. Generation manages, and expects to be able to continue to manage, its commercial activity to ensure that it does not have to register as an SD or MSP or other type of covered financial entity.
There are some rulemaking proceedingspotential adverse outcomes regarding tax positions that have not yet been finalized, in particular, proposed rules on position limitstaken that would apply to both Exchange-traded futures contracts and economically-equivalent over-the-counter swaps. Although the company would incur some costs associated with monitoring and compliance with such rules, it does not expect the rules to have a material impact on its business operations.
The Utility Registrants could also be subject to some Dodd-Frank requirementschallenge by the tax authorities. See Note 1 — Significant Accounting Policies and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants could be negatively affected by federal and state RPS and/or energy conservation legislation, along with energy conservation by customers (All Registrants).
Changes to current state legislation or the extent they were to enter into swaps. However, at this time, managementdevelopment of Federal legislation that requires the use of clean, renewable, and alternate fuel sources could significantly impact Generation and the Utility Registrants, continueespecially if timely cost recovery is not allowed for Utility Registrants. The impact could include increased costs and increased rates for customers.
Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, could increase capital expenditures and could significantly impact the Utility Registrants consolidated financial statements if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to expect that their companies will not be materially affected by Dodd-Frank.a decline in the revenues of the Registrants. See ITEM 1. BUSINESS — Environmental Regulation — Renewable and Clean Energy Standards for additional information.
Generation’s affiliation with the Utility Registrants, together with the presence of a substantial percentage of Generation’s physical asset base within the Utility Registrants' service territories, could increase Generation’s cost of doing business to the extent future complaints or challenges regarding the Utility Registrants' retail rates result in settlements or legislative or regulatory requirements funded in part by Generation (Exelon and Generation).
Generation has significant generating resources within the service areas of the Utility Registrants and makes significant sales to each of them. Those facts tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators, and advocacy groups are aware of Generation’s affiliation with the Utility Registrants and its sales to each of them. In periods of rising utility rates, particularly when driven by increased
costs of energy production and supply, those officials and advocacy groups could question or challenge costs and transactions incurred by the Utility Registrants with Generation, irrespective of any previous regulatory processes or approvals underlying those transactions. These challenges could increase the time, complexity, and cost of the associated regulatory proceedings, and the occurrence of such challenges could subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. In addition, government officials and legislators could seek ways to force Generation to contribute to efforts to mitigate potential or actual rate increases, through measures such as generation-based taxes and contributions to rate-relief packages.
The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants).
The businesses which the Registrants operate are subject to extensive environmental regulation and legislation by local, state and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions and solid waste disposal. Violations of these emission and disposal requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. The Registrants have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future.
If application of Section 316(b) of the Clean Water Act, which establishes a national requirement for reducing the adverse impacts to aquatic organisms at existing generating stations, requires the retrofitting of cooling water intake structures at Salem or other Exelon power plants, this development could result in material costs of compliance. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Additionally, Generation is subject to exposure for asbestos-related personal injury liability alleged at certain current and formerly owned generation facilities. Future legislative action could require Generation to make a material contribution to a fund to settle lawsuits for alleged asbestos-related disease and exposure.
In some cases, a third-party who has acquired assets from a Registrant has assumed the liability the Registrant could otherwise have for environmental matters related to the transferred property. If the transferee is unable, or fails, to discharge the assumed liability, a regulatory authority or injured person could attempt to hold the Registrant responsible, and the Registrant’s remedies against the transferee could be limited by the financial resources of the transferee. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy and subject to appeal, which lead to uncertainty as to the ultimate result and which could introduce time delays in effectuating rate changes (Exelon and the Utility Registrants).
The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. The proceedings generally have timelines that may not be limited by statute. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, bad debt, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs.
In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives or franchise agreements. These settlements are subject to regulatory approval.
The Utility Registrants cannot predict the ultimate outcomes of any settlements or the actions by Illinois, Pennsylvania, Maryland, the District of Columbia, Delaware, New Jersey or Federal regulators in establishing rates, including the extent, if any, to which certain costs such as significant capital projects will be recovered or what rates of return will be allowed. Nevertheless, the expectation is that the Utility Registrants will continue to be obligated to deliver electricity to customers in their respective service territories and will also retain significant default service obligations, referred to as POLR, DSP, SOS and BGS, to provide electricity and natural gas to certain groups of customers in their respective service areas who do not choose an alternative supplier. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants, as applicable, to recover their costs or earn an adequate return and could have a material adverse effect in the Utility Registrants' consolidated financial statements. See Note 4 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding rate proceedings.
Federal or additional state RPS and/or energy conservation legislation, along with energy conservation by customers, could negatively affect the consolidated financial statements of Generation and the Utility Registrants (All Registrants).
Changes to current state legislation or the development of Federal legislation that requires the use of clean, renewable and alternate fuel sources could significantly impact Generation and the Utility Registrants, especially if timely cost recovery is not allowed for Utility Registrants. The impact could include increased costs and increased rates for customers.
Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, have increased capital expenditures and could significantly impact the Utility Registrants if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to a decline in the revenues of Exelon, Generation and the Utility Registrants. For additional information, see ITEM 1. BUSINESS — Environmental Regulation — Renewable and Alternative Energy Portfolio Standards.
The impact of not meeting the criteria of the FASB guidance for accounting for the effects of certain types of regulation could be material to Exelon and the Utility Registrants (Exelon and the Utility Registrants).
As of December 31, 2018, Exelon and the Utility Registrants have concluded that the operations of the Utility Registrants meet the criteria of the authoritative guidance for accounting for the effects of certain types of regulation. If it is concluded in a future period that a separable portion of their businesses no longer meets the criteria, Exelon, and the Utility Registrants would be required to eliminate the financial statement effects of regulation for that part of their business. That action would include the elimination of any or all regulatory assets and liabilities that had been recorded in their Consolidated Balance Sheets and the recognition of a one-time charge in their Consolidated Statements of Operations and Comprehensive Income. The impact of not meeting the criteria of the authoritative guidance could be material to the financial statements of Exelon and the Utility Registrants. The impacts and resolution of the above items could lead to an impairment of ComEd's or PHI’s goodwill, which could be significant and at least partially offset the gains at ComEd discussed above. A significant decrease in equity as a result of any changes could limit the ability of the Utility Registrants to pay dividends under Federal and state law and no longer meeting the regulatory accounting criteria could cause significant volatility in future results of operations. See Note 1 — Significant Accounting Policies, Note 4 — Regulatory Matters and Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for the effects of regulation, regulatory matters and ComEd’s and PHI's goodwill, respectively.
Exelon and Generation could incur material costs of compliance if Federal and/or state regulation or legislation is adopted to address climate change (Exelon and Generation).
Various stakeholders, including legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors, including utilities, are considering ways to address the effect of GHG emissions on climate change. If carbon reduction regulation or legislation becomes effective, Exelon and Generation could incur costs either to limit further the GHG emissions from their operations or to procure emission
allowance credits. See ITEM 1. BUSINESS — Global Climate Change and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding climate change.
The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of PJM’s RTEP and NERC compliance requirements (All Registrants).
As a result of the Energy Policy Act of 2005, users, owners and operators of the bulk power transmission system, including Generation and the Utility Registrants, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. As operators of natural gas distribution systems, PECO, BGE and DPL are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Registrants were found not to be in compliance with the mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards.
See Note 4 — Regulatory Matters and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.taxes.
The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences (All Registrants).
The Registrants have large consumer customer bases and as a result could be the subject of public criticism focused on the operability of their assets and infrastructure and quality of their service.criticism. Adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officialslegislative authorities less likely to view energy companies such as Exelon and its subsidiaries in a favorable light, and could cause Exelon and its subsidiaries to be susceptible
to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements (e.g. disallowances of costs, lower ROEs). The imposition of any of
Legal proceedings could result in a negative outcome, which the foregoing could have a material negative impact on the Registrants' business or consolidated financial statements.
The Registrants cannot predict the outcome of the legal proceedings relating to their business activities. An adverse determination could negatively impact their consolidated financial statements (All Registrants).
The Registrants are involved in legal proceedings, claims, and litigation arising out of their business operations, the most significant of whichoperations. The material ones are summarized in Note 2219 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue, or restrict existing business activities, anyactivities.
Exelon and ComEd have received requests for information related to an SEC investigation into their lobbying activities. The outcome of whichthe investigations could have a material adverse effect on their reputation and consolidated financial statements (Exelon and ComEd).
On October 22, 2019, the SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the Registrants’ consolidated financial statements.
Generationstate of Illinois. Exelon and ComEd have cooperated fully, including by providing all information requested by the SEC, and intend to continue to cooperate fully and expeditiously with the SEC. The outcome of the SEC’s investigation cannot be predicted and could be negatively affected by possible Nuclear Regulatory Commission actions that could affectsubject Exelon and ComEd to civil penalties, sanctions, or other remedial measures. Any of the operations and profitability of its nuclear generating fleet (Exelon and Generation).
Regulatory risk. A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or could result in increased operating or decommissioning costs and significantly affect Generation’s consolidated financial statements. Events at nuclear plants owned by others,foregoing, as well as those owned by Generation,the appearance of non-compliance with anti-corruption and anti-bribery laws, could cause the NRC to initiate such actions.
Spent nuclear fuel storage. The approval of a national repository for the storage of SNF, suchhave an adverse impact on Exelon’s and ComEd’s reputations or relationships with regulatory and legislative authorities, customers, and other stakeholders, as the one previously considered at Yucca Mountain, Nevada, and the timing of such facility opening, will significantly affect the costs associated with storage of SNF, and the ultimate amounts received from the DOE to reimburse Generation for these costs. The NRC’s temporary storage rule (also referred towell as the “waste confidence decision”) recognizes that licensees can safely store SNF at nuclear power plants for up to 60 years beyond the original and renewed licensed operating life of the plants.
Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect Generation’s ability to decommission fully its nuclear units. Through May 15, 2014, in accordance with the NWPA and Generation’s contract with the DOE, Generation paid the DOE a fee per kWh of net nuclear generation for the cost of SNF disposal. This fee was discontinued effective May 16, 2014. Until such time as a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. Generation cannot predict what, if any, fee will be established in the future for SNF disposal. However, such a fee could be material to Generation'stheir consolidated financial statements. See Note 2219 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional informationStatements.
If ComEd violates its Deferred Prosecution Agreement announced on July 17, 2020, it could have an adverse effect on the SNF obligation.reputation and consolidated financial statements of Exelon and ComEd (Exelon and ComEd).
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including, but not limited to, the following: (i) payment to the United States Treasury of $200 million; (ii) continued full cooperation with the government’s investigation; and (iii) ComEd’s adoption and maintenance of remedial measures involving compliance and reporting undertakings as specified in the DPA. If ComEd is found to have breached the terms of the DPA, the USAO may elect to prosecute, or bring a civil action against, ComEd for conduct alleged in the DPA or known to the government, which could result in fines or penalties and could have an adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
Generation’s financial performance could be negatively affected by risks arising from its ownership and operation of hydroelectric facilities (Exelon and Generation).
FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands or connected to the interstate electric grid. Generation cannot predict whether it will receive all the regulatory approvals for the renewed licenses of its hydroelectric facilities. If FERC does not issue new operating licenses for Generation’s hydroelectric facilities or a station cannot be operated through the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation could also lose
revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, could require a substantial increase in capital expenditures, could result in increased operating costs or could render the project uneconomic. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by Generation.
Operational Factors
The Registrants’ employees, contractors, customers and the general public could be exposedRegistrants are subject to a risk of injury due to the nature of the energy industryrisks associated with climate change (All Registrants).
EmployeesThe Registrants periodically perform analyses to better understand how climate change could affect their facilities and contractors throughoutoperations. The Registrants primarily operate in the organization work in,Midwest and customersEast Coast of the United States, areas that historically have been prone to various types of severe weather events, such that the Registrants have well-developed response and recovery programs based on these historical events. However, the general publicRegistrants’ physical facilities could be exposed to, potentially dangerous environments near their operations. As a result, employees, contractors, customersplaced at greater risk of damage should changes in the global climate impact temperature and the general public are at some risk for serious injury, including loss of life. These risks include nuclear accidents, dam failure, gas explosions, pole strikesweather patterns, resulting in more intense, frequent and electric contact cases.
Natural disasters, war, acts and threats of terrorism, pandemic and other significant events could negatively impact the Registrants' results of operations, their ability to raise capital and their future growth (All Registrants).
Generation’s fleet of power plants and the Utility Registrants' distribution and transmission infrastructures could be affected by natural disasters, such as seismic activity, fires resulting from natural causes such as lightning, extreme weather events, changes in temperature andunprecedented levels of precipitation, patterns, changes to ground and surface water availability, sea level rise, and other related phenomena. Severe weather increased surface water temperatures, and/or other natural disasters could be destructive,effects. In addition, changes to the climate may impact levels and patterns of demand for energy and related services, which could result in increased costs, including supply chain costs. An extreme weather event within theaffect Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment.
Natural disasters and other significant events increase the risk to Generation that the NRC or other regulatory or legislative bodies could change the laws or regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning, security and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units. Additionally, natural disasters and other events that have an adverse effect on the economy in general could adversely affect the Registrants’ consolidated financial statements and their ability to raise capital.
The impact that potential terrorist attacks could have on the industry and on Exelon is uncertain. As owner-operators of infrastructure facilities, such as nuclear, fossil and hydroelectric generation facilities and electric and gas transmission and distribution facilities,operations. Over time, the Registrants face a risk that their operations would be direct targets may need to make additional investments to protect facilities from physical climate-related risks and/or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect their operations in unpredictable ways, such asadapt to changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these catastrophic events could compromise the physical or cyber security of Exelon’s facilities, which could adversely affect Exelon’s ability to manage its business effectively. Instability in the financial marketsoperational requirements as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain, which could adversely affect the Registrants’ consolidated financial statements and their ability to raise capital. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.
climate change.
The Registrants also periodically perform analyses of potential pathways to reduce power sector and economy-wide GHG emissions to mitigate climate change. To the extent additional GHG reduction regulation or legislation becomes effective at the Federal and/or state levels, the Registrants could incur costs to further limit the GHG emissions from their operations or otherwise comply with applicable requirements. To the extent such additional regulation or legislation does not become effective, the potential competitive advantage offered by Registrant’s low-carbon emission profile may be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate Exelon's generating and transmission and distribution assets could be affected, resulting in decreased service levels and increased costs.
In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses.reduced. See ITEM 1. BUSINESS — Climate Change Mitigation.
Generation’s financial performance could be negatively affected by matters arising from its ownership and operation of nuclear facilities (Exelon and Generation).
Nuclear capacity factors. Capacity factors for generating units, particularly capacity factors for nuclear generating units, significantly affect Generation’s results of operations. Nuclear plant operations involve substantial fixed operating costs but produce electricity at low variable costs due to nuclear fuel costs typically being lower than fossil fuel costs. Consequently, to be successful, Generation must consistently operate its nuclear facilities at high capacity factors. Lower capacity factors could decrease Generation’s revenues and increase Generation’s operating costs by requiring Generation to produce additional energy from primarily its fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to committed third-party sales, including the Utility Registrants. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations.
Nuclear refueling outages. In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refueling outages, along with their duration, could have a significant impact on Generation’s results of operations. When refueling outages last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease, and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales and higher operating and maintenance costs.
Nuclear fuel quality. The quality of nuclear fuel utilized by Generation could affect the efficiency and costs of Generation’s operations. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs, and/or increased costs due to decreased generation capabilities.
Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation has to shutdownmust shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. Generation could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation could lose revenue and incur increased fuel and purchased power expense to meet supply commitments.
For plants operated but not wholly owned by Generation, Generation could also incur liability to the co-owners. For nuclear plants not operated and not wholly owned by Generation, from which Generation receives a portion of the plants’ output, Generation’s results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants. Additionally, poor operating
performance at nuclear plants not owned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy, which could significantly affect Generation’s consolidated financial statements.energy. In addition, closure of generating plants owned by others, or extended interruptions of generating plants, or failure of transmission lines, could affect transmission systems that could adversely affect the sale and delivery of electricity in markets served by Generation.
Nuclear major incident risk. Although the safety record of nuclear reactors generally has been very good, accidentsrisk and other unforeseen problems have occurred both in the United States and abroad. insurance. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by Generation or owned by others, could exceed Generation’s resources, including insurance coverage. Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation’s nuclear operations. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by Generation and could have a material adverse effect in Generation’s consolidated financial statements.Generation. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned by Generation or others, could result in increased regulation and reduced public support for nuclear-fueled energy and significantly adversely affect Generation’s consolidated financial statements.energy.
Nuclear insurance. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance, $450 million for each operating site. Claims exceeding that amount are covered through
mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $14.1$13.8 billion limit for a single incident.
Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation’s nuclear operations. In previous years, NEIL has made distributions to its members but Generation cannot predict the level of future distributions or if they will occur at all. See Note 2219 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of nuclear insurance.
Decommissioning obligation and funding. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired and units that are within five years of retirement) addressing Generation’s ability to meet the NRC-estimated funding levels including scheduled contributions to and earnings on the NDT funds. The NRC funding levels are based upon the assumption that decommissioning will commence after the end of the current licensed life of each unit.
Generation recognizes as a liability the present value of the estimated future costs to decommission its nuclear facilities. The estimated liability is based on assumptions in the approach and timing of decommissioning the nuclear facilities, estimation of decommissioning costs, and Federal and state regulatory requirements. No assurance can be given that theThe costs of such decommissioning will notmay substantially exceed such liability, as facts, circumstances or our estimates may change, including changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in Federal or state regulatory requirements on the decommissioning of such facilities, other changes in our estimates or Generation’s ability to effectively execute on its planned decommissioning activities.
The performance of capital markets could significantly affect the value of the trust funds. Currently, Generation is makingmakes contributions to certain trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to Generation. While Generation, through PECO, has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from utility customers for any of its other nuclear units if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation would be unable to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units could be negatively affected and Exelon’s and Generation’s consolidated financial statements could be significantly affected. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. Ultimately, if the investments held by Generation’s NDTs are not sufficient to fund the decommissioning of Generation’s nuclear units, Generation could be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met. As a result, Generation’s consolidated financial statements could be significantly adversely affected. Additionally, if the pledged assets are not sufficient to fund the Zion Station decommissioning activities under the Asset Sale Agreement (ASA), Generation could have to seek remedies available under the ASA to reduce the risk of default by ZionSolutions and its parent. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
For nuclear units that are subject to regulatory agreements with either the ICC or the PAPUC, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statements of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation. ComEd and PECO have recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability.
IfShould the expected value inof the NDT fundsfund for any nuclearformer ComEd unit subject tofall below the regulatory agreements withamount of the ICC is expected to not exceed the total decommissioning obligation for that unit, the accounting to offset decommissioning-
relateddecommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income, and the adverse impact to Exelon’s and Generation’s consolidated financial statements could be material. For the nuclear units subjectAny changes to the regulatory agreements with the PAPUC, any changes to theexisting PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s consolidated financial statements could be material.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. If the accountinginvestments held by Generation’s NDT funds are not sufficient to offset decommissioning-related activities is discontinued, any remaining balances in noncurrent payables to affiliates atfund the decommissioning of Generation’s nuclear units, Generation and ComEd's or PECO’s noncurrent affiliate receivable from Generation and corresponding regulatory liability may need to be reversed and could have a material impact in Generation’s Consolidated Statement of Operations and Comprehensive Income.
Generation’s financial performance could be negatively affected by risks arising from its ownership and operationrequired to take steps, such as providing financial guarantees through letters of hydroelectric facilities (Exelon and Generation).credit or parent
FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands
company guarantees or connectedmaking additional contributions to the interstate electric grid. The license fortrusts, which could be significant, to ensure that the Muddy Run Pumped Storage Project expires on December 1, 2055. The license for the Conowingo Hydroelectric Project expired on September 1, 2014. FERC issued an annual license, effective astrusts are adequately funded and that current and future NRC minimum funding requirements are met.
See Note 10 — Asset Retirement Obligations of the expiration of the previous license. If FERC does not issue a license priorCombined Notes to the expiration of the annual license, the annual license renews automatically. Generation cannot predict whether it will receive all the regulatory approvals for the renewed licenses of its hydroelectric facilities. If FERC does not issue new operating licenses for Generation’s hydroelectric facilities or a station cannot be operated through the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation could also lose revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, could require a substantial increase in capital expenditures, could result in increased operating costs or could render the project uneconomic and significantly affect Generation’s consolidated financial statements. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by Generation.
The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability (All Registrants).
The Registrants’ businesses are capital intensive and require significant investments by Generation in electric generating facilities and by the Utility Registrants in transmission and distribution infrastructure projects. These operational systems and infrastructure have been in service for many years. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Registrants’ control, and could require significant expenditures to operate efficiently. The Registrants’ respective consolidated financial statements could be adversely affected if they were unable to effectively manage their capital projects or raise the necessary capital. Furthermore, operational failure of electric or gas systems, generation facilities or infrastructure could result in potential liability if such failure results in damage to property or injury to individuals. See ITEM 1. BUSINESSConsolidated Financial Statements for additional information regarding the Registrants’ potential future capital expenditures.information.
The Utility Registrants' operating costs and customers’ and regulators’ opinions of the Utility Registrants are affected by their ability to maintain the availability and reliability of their delivery and operational systems (Exelon and the Utility Registrants).
Failures of the equipment or facilities including information systems, used in the Utility Registrants' delivery systems could interrupt the electric transmission and electric and natural gas delivery, which could negatively impact relatedresult in a loss of revenues and an increase in maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of advanced metering infrastructure,AMI, smart grid, or other technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems, the Utility Registrants' consolidated financial statements could be negatively impacted. Furthermore,or if
any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results could be negatively impacted. If an employee or third party causes the operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating the operational systems, the Utility Registrants' financial results could also be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal and/or external tampering or manipulation of those systems will result in losses that are difficult to detect.
The aforementioned failures or those of other utilities, including prolonged or repeated failures, could affect customer satisfaction and the level of regulatory oversight and the Utility Registrants' maintenance and capital expenditures. Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers, and those damageswhich could be material to ComEd’s consolidated financial statements.
The Utility Registrants' respective ability to deliver electricity, their operating costs and their capital expenditures could be negatively impacted by transmission congestion and failures of neighboring transmission systems (Exelon and the Utility Registrants).
Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage with consequent effects on operating costs, revenues and results of operations. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures.
The electricity transmission facilities of the Utility Registrants are interconnected with the transmission facilities of neighboring utilities and are part of the interstate power transmission grid that is operated by PJM RTO. Although PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities, there can be no assurance that service interruptions at other utilities will not cause interruptions in the Utility Registrants’ service areas. If the Utility Registrants were to suffer such a service interruption, it could have a negative impact in their and Exelon’s consolidated financial statements.material.
The Registrants are subject to physical security and cybersecurity risks (All Registrants).
The Registrants face physical security and cybersecurity risks as the owner-operators of generation, transmission and distribution facilities and as participants in commodities trading.risks. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural gas utility industry associated with protection of sensitive and confidential information, grid infrastructure, and other energy infrastructures, and such attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of advanced digital technologies increases the potentially unfavorable impacts of such attacks. A security breach of the physical assets or information systems of the Registrants, their competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor, and employee data, trading or other confidential data. The risk of these system-related events and security breaches occurring continues to intensify, and while the Registrants have been, and will likely continue to be, subjected to physical and cyber-attacks, to date none has directly experienced a material breach or disruption to its network or information systems or our service operations. However, as such attacks continue to increase in sophistication and frequency, the Registrants may be unable to prevent all such attacks in the future. If a significant breach were to occur, the reputation of Exelon or another Registrant and its customer supply activitiesthe Registrants could be adverselynegatively affected, customer confidence in the Registrants or others in the industry could be diminished, or Exelon and its subsidiariesthe Registrants could be subject to legal claims, loss of revenues, increased costs, or operations shutdown, etc., any of which could contribute to the loss of customers and have a negative impact on the business and/or consolidated financial statements.shutdown. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result.
The Utility Registrants' deployment of smart meters throughout their service territories could increase the
risk of damage from an intentional disruption of the system by third parties.
In addition, new or updated security regulations or unforeseen threat sources could require changes in current measures taken by the Registrants or their business operations and could adversely affect their consolidated financial statements.
FailureThe Registrants’ employees, contractors, customers, and the general public could be exposed to a risk of injury due to the nature of the energy industry (All Registrants).
Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous environments near the Registrants’ operations. As a result, employees,
contractors, customers, and the general public are at some risk for serious injury, including loss of life. These risks include nuclear accidents, dam failure, gas explosions, pole strikes, and electric contact cases.
Natural disasters, war, acts and threats of terrorism, pandemic, and other significant events could negatively impact the Registrants' results of operations, their ability to raise capital and their future growth (All Registrants).
Generation’s fleet of power plants and the Utility Registrants' distribution and transmission infrastructures could be affected by natural disasters and extreme weather events, which could result in increased costs, including supply chain costs. An extreme weather event within the Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Natural disasters and other significant events increase the risk to Generation that the NRC or other regulatory or legislative bodies could change the laws or regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning, security, and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units.
The impact that potential terrorist attacks could have on the industry and on Exelon is uncertain. The Registrants face a risk that their operations would be direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect their operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these catastrophic events could compromise the physical or cybersecurity of Exelon’s facilities, which could adversely affect Exelon’s ability to manage its business effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession, or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.
The Registrants could be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate Exelon's generating and transmission and distribution assets could be affected.
In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses.
The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability (All Registrants).
The Registrants’ businesses are capital intensive and require significant investments by Generation in electric generating facilities and by the Utility Registrants in transmission and distribution infrastructure projects. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Registrants’ control, and could require significant expenditures to operate efficiently. The Registrants consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources for additional information regarding the Registrants’ potential future capital expenditures.
The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by transmission congestion and failures of neighboring transmission systems (Exelon and the Utility Registrants).
Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission
capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures.
PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. However, service interruptions at other utilities may cause interruptions in the Utility Registrants’ service areas.
The Registrants consolidated financial statements could be negatively affected if they fail to attract and retain an appropriately qualified workforce could negatively impact the Registrants’ consolidated financial statements (All Registrants).
Certain events, such as an employee strike, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, could arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their generation, transmission, and distribution operations. If the Registrants are unable to successfully attract and retain an appropriately qualified workforce, their consolidated financial statements could be negatively impacted.
The Registrants could make acquisitions or investments in new business initiatives including initiatives mandated by regulators, and new markets, thatwhich may not be successful and acquisitions could notor achieve the intended financial results (All Registrants).
Generation could continue to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. This could include investment opportunities in renewables, development of natural gas generation, nuclear advisory or operating services for third parties, distributed generation, potential expansion of the existing wholesale gas businesses, and entry into liquefied natural gas.LNG. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered in theduring diligence performed prior to launching an initiative or entering a market. As these markets mature, there could be new market entrants or expansion by established competitors that increase competition for customers and resources. Additionally, it is possible that FERC, state public utility commissions or others could impose certain other restrictions on such transactions. All of these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment.
The Utility Registrants face risks associated with their regulatory-mandated Smart Gridinitiatives, such as smart grids and utility of the future initiatives and other non-regulatory mandated initiatives.future. These risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity, and obsolescence of technology. Due to these risks, no assurance canSuch initiatives may not be given that such initiatives will be successful and will not have a material adverse effect in the Utility Registrants' consolidated financial statements.successful.
The Registrants may not realize or achieve the anticipated cost savings through the cost management efforts which could impact the Registrants’ results of operations (All Registrants).
The Registrants’ future financial performance and level of profitability is dependent, in part, on various cost reduction initiatives. The Registrants may encounter challenges in executing these cost reduction initiatives and not achieve the intended cost savings.
Risks Related to the Planned Separation (Exelon and Generation) The planned separation is contingent upon regulatory approvals and satisfaction of other conditions and may not be completed in accordance with the expected plans or anticipated timeline, or at all, which could negatively affect Exelon’s and Generation’s consolidated financial statements.
Exelon is targeting to complete the separation in the first quarter of 2022, subject to final approval by Exelon’s Board of Directors, a Form 10 registration statement being declared effective by the SEC, regulatory approvals, and satisfaction of other conditions. The planned separation is subject to approval by the FERC, NRC and NYPSC. There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing. If the planned separation is not completed or is delayed, Exelon’s and Generation’s consolidated financial statements may be materially adversely affected, and the market price of Exelon’s common stock may be affected.
The plan to separate into two publicly traded companies will involve significant time and expense, which could disrupt or adversely affect our business.
The planned separation is complex in nature, and unanticipated developments or changes, including challenges in executing the separation, could delay or prevent the completion of the proposed separation, or cause the separation to occur on terms or conditions that are different or less favorable than expected. Additionally, Exelon’s Board of Directors, in its sole and absolute discretion, may decide not to proceed with the separation at any time prior to the distribution date. The process of completing the proposed separation has been and is expected to continue to be time-consuming and involves significant costs and expenses.
The planned separation may not achieve some or all of the anticipated benefits and each separate company following the separation may underperform relative to Exelon’s expectations.
By separating the Utility Registrants and Generation, Exelon is creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separate companies are expected to create value by having the strategic flexibility to focus on their unique customer, market and community priorities. However, the planned separation may not provide such results on the scope or scale that Exelon anticipates, and Exelon and Generation may not realize the anticipated benefits of the planned separation. Failure to do so could have a material adverse effect on the financial statements of each separate company and their respective common stock price.
Following the planned separation, the companies anticipate to maintain investment grade credit ratings. Ratings are based upon assessments of multiple factors, including a company’s credit metrics as well as industry and macroeconomic changes and trends. If a rating agency were to downgrade the rating below investment grade, the separate companies’ borrowing costs would increase and their funding sources could decrease, which could have a material adverse effect on the financial statements of the affected company.
The common stock of the separately publicly traded companies following the separation may collectively trade at a value less than the price at which Exelon’s common stock might have traded had the separation not occurred.
There could be significant liability if the planned spin-off is determined to be a taxable transaction.
Under the separation plan, Exelon shareholders will retain their current shares of Exelon stock and receive a pro-rata distribution of shares of the new company’s stock in a transaction that is expected to be tax-free to Exelon and its shareholders under Sections 355 and 368 of the IRC. Exelon will seek a private letter ruling from the IRS regarding the tax-free nature of the transaction. Exelon will also seek from its tax advisors an opinion with respect to certain U.S. federal income tax consequences of the spin-off. If the planned spin-off ultimately is determined to be taxable, the spin-off could be treated as a taxable dividend to Exelon’s shareholders for U.S. federal income tax purposes, and Exelon’s shareholders could incur significant U.S. federal income tax liabilities. In addition, Exelon would recognize a taxable gain to the extent that the fair market value of the new company’s stock exceeds its tax basis in such stock on the date of the planned separation. Exelon will enter into a Tax Matters Agreement with the new company to address how post-separation issues will be managed between the companies, as well as which company is responsible for taxes imposed as a result of the planned separation, if any.
See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information on the planned separation.
|
| | | | |
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
All Registrants
None.
Generation
The following table describespresents Generation’s interests in net electric generating capacity by station at December 31, 2018:2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Station(a) | | Location | | No. of
Units | | Percent Owned(b) | | Primary
Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
| Midwest | | | | | | | | | | | | | |
| Braidwood | | Braidwood, IL | | 2 | | | | | Uranium | | Base-load | | 2,386 | | |
| Byron | | Byron, IL | | 2 | | | | | Uranium | | Base-load | | 2,347 | | (e) |
| LaSalle | | Seneca, IL | | 2 | | | | | Uranium | | Base-load | | 2,320 | | |
| Dresden | | Morris, IL | | 2 | | | | | Uranium | | Base-load | | 1,845 | | (e) |
| Quad Cities | | Cordova, IL | | 2 | | | 75 | | | Uranium | | Base-load | | 1,403 | | (f) |
| Clinton | | Clinton, IL | | 1 | | | | | Uranium | | Base-load | | 1,080 | | |
| Michigan Wind 2 | | Sanilac Co., MI | | 50 | | | 51 | | (g) | Wind | | Intermittent | | 46 | | (f) |
| Beebe | | Gratiot Co., MI | | 34 | | | 51 | | (g) | Wind | | Intermittent | | 42 | | (f) |
| Michigan Wind 1 | | Huron Co., MI | | 46 | | | 51 | | (g) | Wind | | Intermittent | | 35 | | (f) |
| Harvest 2 | | Huron Co., MI | | 33 | | | 51 | | (g) | Wind | | Intermittent | | 30 | | (f) |
| Harvest | | Huron Co., MI | | 32 | | | 51 | | (g) | Wind | | Intermittent | | 27 | | (f) |
| Beebe 1B | | Gratiot Co., MI | | 21 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) |
| City Solar | | Chicago, IL | | 1 | | | | | Solar | | Intermittent | | 9 | | |
| Solar Ohio | | Toledo, OH | | 2 | | | | | Solar | | Intermittent | | 4 | | (h) |
| Blue Breezes | | Faribault Co., MN | | 2 | | | | | Wind | | Intermittent | | 3 | | |
| CP Windfarm | | Faribault Co., MN | | 2 | | | 51 | | (g) | Wind | | Intermittent | | 2 | | (f) |
| Southeast Chicago | | Chicago, IL | | 8 | | | | | Gas | | Peaking | | 296 | | (i) |
| Clinton Battery Storage | | Blanchester, OH | | 1 | | | | | Energy Storage | | Peaking | | 10 | | |
| Total Midwest | | | | | | | | | | | | 11,911 | | |
| | | | | | | | | | | | | |
| Mid-Atlantic | | | | | | | | | | | | | |
| Limerick | | Sanatoga, PA | | 2 | | | | | Uranium | | Base-load | | 2,317 | | |
| Peach Bottom | | Delta, PA | | 2 | | | 50 | | | Uranium | | Base-load | | 1,324 | | (f) |
| Salem | | Lower Alloways
Creek Township, NJ | | 2 | | | 42.59 | | | Uranium | | Base-load | | 995 | | (f) |
| Calvert Cliffs | | Lusby, MD | | 2 | | | 50.01 | | (j) | Uranium | | Base-load | | 895 | | (f) |
| Conowingo | | Darlington, MD | | 11 | | | | | Hydroelectric | | Base-load | | 572 | | |
| Criterion | | Oakland, MD | | 28 | | | 51 | | (g) | Wind | | Intermittent | | 36 | | (f) |
| Fair Wind | | Garrett County, MD | | 12 | | | | | Wind | | Intermittent | | 30 | | |
| Solar MC | | Various, MD | | 44 | | | | | Solar | | Intermittent | | 44 | | (h) |
| Fourmile Ridge | | Garrett County, MD | | 16 | | | 51 | | (g) | Wind | | Intermittent | | 20 | | (f) |
| Solar New Jersey 1 | | Various, NJ | | 5 | | | | | Solar | | Intermittent | | 18 | | (h) |
| Solar New Jersey 2 | | Various, NJ | | 2 | | | | | Solar | | Intermittent | | 11 | | (h) |
| Solar Horizons | | Emmitsburg, MD | | 1 | | | 51 | | (g) | Solar | | Intermittent | | 16 | | (f) |
| Solar Maryland | | Various, MD | | 11 | | | | | Solar | | Intermittent | | 8 | | (h) |
| Solar Maryland 2 | | Various, MD | | 3 | | | | | Solar | | Intermittent | | 8 | | (h) |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
| Braidwood | Midwest | Braidwood, IL | 2 |
| | Uranium | Base-load | 2,386 |
| |
| Byron | Midwest | Byron, IL | 2 |
| | Uranium | Base-load | 2,347 |
| |
| LaSalle | Midwest | Seneca, IL | 2 |
| | Uranium | Base-load | 2,320 |
| |
| Dresden | Midwest | Morris, IL | 2 |
| | Uranium | Base-load | 1,845 |
| |
| Quad Cities | Midwest | Cordova, IL | 2 |
| 75 |
| Uranium | Base-load | 1,403 |
| (e) |
| Clinton | Midwest | Clinton, IL | 1 |
| | Uranium | Base-load | 1,069 |
| |
| Michigan Wind 2 | Midwest | Sanilac Co., MI | 50 |
| 51 |
| Wind | Base-load | 46 |
| (e)(g) |
| Beebe | Midwest | Gratiot Co., MI | 34 |
| 51 |
| Wind | Base-load | 42 |
| (e)(h) |
| Michigan Wind 1 | Midwest | Huron Co., MI | 46 |
| 51 |
| Wind | Base-load | 35 |
| (e)(g) |
| Harvest 2 | Midwest | Huron Co., MI | 33 |
| 51 |
| Wind | Base-load | 30 |
| (e)(g) |
| Harvest | Midwest | Huron Co., MI | 32 |
| 51 |
| Wind | Base-load | 27 |
| (e)(g) |
| Beebe 1B | Midwest | Gratiot Co., MI | 21 |
| 51 |
| Wind | Base-load | 26 |
| (e)(g) |
| Ewington | Midwest | Jackson Co., MN | 10 |
| 99 |
| Wind | Base-load | 20 |
| (e) |
| Marshall | Midwest | Lyon Co., MN | 9 |
| 99 |
| Wind | Base-load | 19 |
| (e) |
| City Solar | Midwest | Chicago, IL | 1 |
| | Solar | Base-load | 9 |
| |
| Solar Ohio | Midwest | Toledo, OH | 2 |
| | Solar | Base-load | 4 |
| |
| Blue Breezes | Midwest | Faribault Co., MN | 2 |
| | Wind | Base-load | 3 |
| |
| CP Windfarm | Midwest | Faribault Co., MN | 2 |
| 51 |
| Wind | Base-load | 2 |
| (e)(g) |
| Southeast Chicago | Midwest | Chicago, IL | 8 |
| | Gas | Peaking | 296 |
| (k) |
| Clinton Battery Storage | Midwest | Blanchester, OH | 1 |
| | Energy Storage | Peaking | 10 |
| |
| Total Midwest | | | | | | | 11,939 |
| |
| | | | | | | | | |
| Limerick | Mid-Atlantic | Sanatoga, PA | 2 |
| | Uranium | Base-load | 2,317 |
| |
| Peach Bottom | Mid-Atlantic | Delta, PA | 2 |
| 50 |
| Uranium | Base-load | 1,324 |
| (e) |
| Salem | Mid-Atlantic | Lower Alloways Creek Township, NJ | 2 |
| 42.59 |
| Uranium | Base-load | 1,002 |
| (e) |
| Calvert Cliffs | Mid-Atlantic | Lusby, MD | 2 |
| 50.01 |
| Uranium | Base-load | 895 |
| (e)(f) |
| Three Mile Island | Mid-Atlantic | Middletown, PA | 1 |
| | Uranium | Base-load | 837 |
| (j) |
| Conowingo | Mid-Atlantic | Darlington, MD | 11 |
| | Hydroelectric | Base-load | 572 |
| |
| Criterion | Mid-Atlantic | Oakland, MD | 28 |
| 51 |
| Wind | Base-load | 36 |
| (e)(g) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Station(a) | | Location | | No. of
Units | | Percent Owned(b) | | Primary
Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
| JBAB Solar | | District of Columbia | | 4 | | | | | Solar | | Intermittent | | 7 | | (h) |
| Gateway Solar | | Berlin, MD | | 1 | | | | | Solar | | Intermittent | | 7 | | (h) |
| Constellation New Energy | | Gaithersburg, MD | | 2 | | | | | Solar | | Intermittent | | 6 | | (h) |
| Solar Federal | | Trenton, NJ | | 1 | | | | | Solar | | Intermittent | | 5 | | (h) |
| Solar New Jersey 3 | | Middle Township, NJ | | 5 | | | 51 | | (g) | Solar | | Intermittent | | 2 | | (f) |
| Solar DC | | District of Columbia | | 1 | | | | | Solar | | Intermittent | | 1 | | (h) |
| Muddy Run | | Drumore, PA | | 8 | | | | | Hydroelectric | | Intermediate | | 1,070 | | |
| Eddystone 3, 4 | | Eddystone, PA | | 2 | | | | | Oil/Gas | | Peaking | | 760 | | |
| Perryman | | Aberdeen, MD | | 5 | | | | | Oil/Gas | | Peaking | | 404 | | |
| Croydon | | West Bristol, PA | | 8 | | | | | Oil | | Peaking | | 391 | | |
| Handsome Lake | | Kennerdell, PA | | 5 | | | | | Gas | | Peaking | | 268 | | |
| Richmond | | Philadelphia, PA | | 2 | | | | | Oil | | Peaking | | 98 | | |
| Philadelphia Road | | Baltimore, MD | | 4 | | | | | Oil | | Peaking | | 61 | | |
| Eddystone | | Eddystone, PA | | 4 | | | | | Oil | | Peaking | | 60 | | |
| Delaware | | Philadelphia, PA | | 4 | | | | | Oil | | Peaking | | 56 | | |
| Southwark | | Philadelphia, PA | | 4 | | | | | Oil | | Peaking | | 52 | | |
| Falls | | Morrisville, PA | | 3 | | | | | Oil | | Peaking | | 51 | | |
| Moser | | Lower Pottsgrove Twp., PA | | 3 | | | | | Oil | | Peaking | | 51 | | |
| Chester | | Chester, PA | | 3 | | | | | Oil | | Peaking | | 39 | | |
| Schuylkill | | Philadelphia, PA | | 2 | | | | | Oil | | Peaking | | 30 | | |
| Salem | | Lower Alloways
Creek Township, NJ | | 1 | | | 42.59 | | | Oil | | Peaking | | 16 | | (f) |
| Total Mid-Atlantic | | | | | | | | | | | | 9,729 | | |
| | | | | | | | | | | | | |
| ERCOT | | | | | | | | | | | | | |
| Whitetail | | Webb County, TX | | 57 | | | 51 | | (g) | Wind | | Intermittent | | 47 | | (f) |
| Sendero | | Jim Hogg and Zapata County, TX | | 39 | | | 51 | | (g) | Wind | | Intermittent | | 40 | | (f) |
| Constellation Solar Texas | | Various, TX | | 11 | | | | | Solar | | Intermittent | | 13 | | (h) |
| Colorado Bend II | | Wharton, TX | | 3 | | | | | Gas | | Intermediate | | 1,143 | | |
| Wolf Hollow II | | Granbury, TX | | 3 | | | | | Gas | | Intermediate | | 1,115 | | |
| Handley 3 | | Fort Worth, TX | | 1 | | | | | Gas | | Intermediate | | 395 | | |
| Handley 4, 5 | | Fort Worth, TX | | 2 | | | | | Gas | | Peaking | | 870 | | |
| Total ERCOT | | | | | | | | | | | | 3,623 | | |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
| Fair Wind | Mid-Atlantic | Garrett County, MD | 12 |
| | Wind | Base-load | 30 |
| |
| Solar Maryland MC | Mid-Atlantic | Various, MD | 40 |
| | Solar | Base-load | 36 |
| |
| Fourmile | Mid-Atlantic | Garrett County, MD | 16 |
| 51 |
| Wind | Base-load | 20 |
| (e)(g) |
| Solar New Jersey 1 | Mid-Atlantic | Various, NJ | 5 |
| | Solar | Base-load | 18 |
| |
| Solar New Jersey 2 | Mid-Atlantic | Various, NJ | 2 |
| | Solar | Base-load | 11 |
| |
| Solar Horizons | Mid-Atlantic | Emmitsburg, MD | 1 |
| 51 |
| Solar | Base-load | 8 |
| (e)(g) |
| Solar Maryland | Mid-Atlantic | Various, MD | 11 |
| | Solar | Base-load | 8 |
| |
| Solar Maryland 2 | Mid-Atlantic | Various, MD | 3 |
| | Solar | Base-load | 8 |
| |
| Constellation New Energy | Mid-Atlantic | Gaithersburg, MD | 1 |
| | Solar | Base-load | 5 |
| |
| Solar Federal | Mid-Atlantic | Trenton, NJ | 1 |
| | Solar | Base-load | 5 |
| |
| Solar New Jersey 3 | Mid-Atlantic | Middle Township, NJ | 5 |
| 51 |
| Solar | Base-load | 1 |
| (e)(g) |
| Solar DC | Mid-Atlantic | District of Columbia | 1 |
| | Solar | Base-load | 1 |
| |
| Muddy Run | Mid-Atlantic | Drumore, PA | 8 |
| | Hydroelectric | Intermediate | 1,070 |
| |
| Eddystone 3, 4 | Mid-Atlantic | Eddystone, PA | 2 |
| | Oil/Gas | Intermediate | 760 |
| |
| Perryman | Mid-Atlantic | Aberdeen, MD | 5 |
| | Oil/Gas | Peaking | 404 |
| |
| Croydon | Mid-Atlantic | West Bristol, PA | 8 |
| | Oil | Peaking | 391 |
| |
| Handsome Lake | Mid-Atlantic | Kennerdell, PA | 5 |
| | Gas | Peaking | 268 |
| |
| Notch Cliff | Mid-Atlantic | Baltimore, MD | 8 |
| | Gas | Peaking | 117 |
| (k) |
| Westport | Mid-Atlantic | Baltimore, MD | 1 |
| | Gas | Peaking | 116 |
| (k) |
| Richmond | Mid-Atlantic | Philadelphia, PA | 2 |
| | Oil | Peaking | 98 |
| |
| Gould Street | Mid-Atlantic | Baltimore, MD | 1 |
| | Gas | Peaking | 97 |
| (k) |
| Philadelphia Road | Mid-Atlantic | Baltimore, MD | 4 |
| | Oil | Peaking | 61 |
| |
| Eddystone | Mid-Atlantic | Eddystone, PA | 4 |
| | Oil | Peaking | 60 |
| |
| Fairless Hills | Mid-Atlantic | Fairless Hills, PA | 2 |
| | Landfill Gas | Peaking | 60 |
| (k) |
| Delaware | Mid-Atlantic | Philadelphia, PA | 4 |
| | Oil | Peaking | 56 |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Station(a) | | Location | | No. of
Units | | Percent Owned(b) | | Primary
Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
| New York | | | | | | | | | | | | | |
| Nine Mile Point | | Scriba, NY | | 2 | | | 50.01 | | (j) | Uranium | | Base-load | | 838 | | (f) |
| FitzPatrick | | Scriba, NY | | 1 | | | | | Uranium | | Base-load | | 842 | | |
| Ginna | | Ontario, NY | | 1 | | | 50.01 | | (j) | Uranium | | Base-load | | 288 | | (f) |
| Solar New York | | Bethlehem, NY | | 1 | | | | | Solar | | Intermittent | | 3 | | (h) |
| Total New York | | | | | | | | | | | | 1,971 | | |
| | | | | | | | | | | | | |
| Other | | | | | | | | | | | | | |
| Antelope Valley | | Lancaster, CA | | 1 | | | | | Solar | | Intermittent | | 242 | | |
| Bluestem | | Beaver County, OK | | 60 | | | 51 | | (g)(k) | Wind | | Intermittent | | 101 | | (f) |
| Shooting Star | | Kiowa County, KS | | 65 | | | 51 | | (g) | Wind | | Intermittent | | 53 | | (f) |
| Albany Green Energy | | Albany, GA | | 1 | | | 99 | | (l) | Biomass | | Base-load | | 50 | | (f) |
| Solar Arizona | | Various, AZ | | 127 | | | | | Solar | | Intermittent | | 46 | | (h) |
| Bluegrass Ridge | | King City, MO | | 27 | | | 51 | | (g) | Wind | | Intermittent | | 29 | | (f) |
| California PV Energy 2 | | Various, CA | | 89 | | | | | Solar | | Intermittent | | 27 | | (h) |
| Conception | | Barnard, MO | | 24 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) |
| Cow Branch | | Rock Port, MO | | 24 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) |
| Solar Arizona 2 | | Various, AZ | | 56 | | | | | Solar | | Intermittent | | 34 | | (h) |
| California PV Energy | | Various, CA | | 53 | | | | | Solar | | Intermittent | | 21 | | (h) |
| Mountain Home | | Glenns Ferry, ID | | 20 | | | 51 | | (g) | Wind | | Intermittent | | 21 | | (f) |
| High Mesa | | Elmore Co., ID | | 19 | | | 51 | | (g) | Wind | | Intermittent | | 20 | | (f) |
| Echo 1 | | Echo, OR | | 21 | | | 50.49 | | (g) | Wind | | Intermittent | | 17 | | (f) |
| Sacramento PV Energy | | Sacramento, CA | | 4 | | | 51 | | (g) | Solar | | Intermittent | | 30 | | (f) |
| Cassia | | Buhl, ID | | 14 | | | 51 | | (g) | Wind | | Intermittent | | 15 | | (f) |
| Wildcat | | Lovington, NM | | 13 | | | 51 | | (g) | Wind | | Intermittent | | 14 | | (f) |
| Echo 2 | | Echo, OR | | 10 | | | 51 | | (g) | Wind | | Intermittent | | 10 | | (f) |
| Solar Georgia 2 | | Various, GA | | 8 | | | | | Solar | | Intermittent | | 10 | | (h) |
| Tuana Springs | | Hagerman, ID | | 8 | | | 51 | | (g) | Wind | | Intermittent | | 9 | | (f) |
| Solar Georgia | | Various, GA | | 10 | | | | | Solar | | Intermittent | | 8 | | (h) |
| Greensburg | | Greensburg, KS | | 10 | | | 51 | | (g) | Wind | | Intermittent | | 6 | | (f) |
| Solar Massachusetts | | Various, MA | | 10 | | | | | Solar | | Intermittent | | 7 | | (h) |
| Outback Solar | | Christmas Valley, OR | | 1 | | | | | Solar | | Intermittent | | 6 | | (h) |
| Echo 3 | | Echo, OR | | 6 | | | 50.49 | | (g) | Wind | | Intermittent | | 5 | | (f) |
| Holyoke Solar | | Various, MA | | 2 | | | | | Solar | | Intermittent | | 5 | | (h) |
| Three Mile Canyon | | Boardman, OR | | 6 | | | 51 | | (g) | Wind | | Intermittent | | 5 | | (f) |
| Loess Hills | | Rock Port, MO | | 4 | | | | | Wind | | Intermittent | | 5 | | |
| California PV Energy 3 | | Various, CA | | 31 | | | | | Solar | | Intermittent | | 8 | | (h) |
| Denver Airport Solar | | Denver, CO | | 1 | | | 51 | | (g) | Solar | | Intermittent | | 4 | | (f) |
| Solar Net Metering | | Uxbridge, MA | | 1 | | | | | Solar | | Intermittent | | 2 | | (h) |
| Solar Connecticut | | Various, CT | | 1 | | | | | Solar | | Intermittent | | 1 | | (h) |
| Mystic 8, 9 | | Charlestown, MA | | 6 | | | | | Gas | | Intermediate | | 1,413 | | (e) |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
| Southwark | Mid-Atlantic | Philadelphia, PA | 4 |
| | Oil | Peaking | 52 |
| |
| Falls | Mid-Atlantic | Morrisville, PA | 3 |
| | Oil | Peaking | 51 |
| |
| Moser | Mid-Atlantic | Lower PottsgroveTwp., PA | 3 |
| | Oil | Peaking | 51 |
| |
| Riverside | Mid-Atlantic | Baltimore, MD | 2 |
| | Oil | Peaking | 39 |
| (k)(l) |
| Chester | Mid-Atlantic | Chester, PA | 3 |
| | Oil | Peaking | 39 |
| |
| Schuylkill | Mid-Atlantic | Philadelphia, PA | 2 |
| | Oil | Peaking | 30 |
| |
| Salem | Mid-Atlantic | Lower Alloways Creek Township, NJ | 1 |
| 42.59 |
| Oil | Peaking | 16 |
| (e) |
| Pennsbury | Mid-Atlantic | Morrisville, PA | 2 |
| | Landfill Gas | Peaking | 4 |
| (e) |
| Bethlehem | Mid-Atlantic | Bethlehem, PA | 1 |
| | Landfill Gas | Peaking | 4 |
| (k) |
| Eastern | Mid-Atlantic | Bethlehem, PA | 3 |
| | Landfill Gas | Peaking | 4 |
| (k) |
| Total Mid-Atlantic | | | | | | | 10,982 |
| |
| | | | | | | | | |
| Whitetail | ERCOT | Webb County, TX | 57 |
| 51 |
| Wind | Base-load | 46 |
| (e)(g) |
| Sendero | ERCOT | Jim Hogg and Zapata County, TX | 39 |
| 51 |
| Wind | Base-load | 40 |
| (e)(g) |
| Constellation Solar Texas | Other | Various, TX | 11 |
| | Solar | Base-load | 13 |
| |
| Colorado Bend II | ERCOT | Wharton, TX | 3 |
| | Gas | Intermediate | 1,088 |
| |
| Wolf Hollow II | ERCOT | Granbury, TX | 3 |
| | Gas | Intermediate | 1,064 |
| |
| Handley 3 | ERCOT | Fort Worth, TX | 1 |
| | Gas | Intermediate | 395 |
| |
| Handley 4, 5 | ERCOT | Fort Worth, TX | 2 |
| | Gas | Peaking | 870 |
| |
| Total ERCOT | | | | | | | 3,516 |
| |
| | | | | | | | | |
Solar Massachusetts | New England | Various, MA | 10 |
| | Solar | Base-load | 7 |
| |
| Holyoke Solar | New England | Various, MA | 2 |
| | Solar | Base-load | 5 |
| |
| Solar Net Metering | New England | Uxbridge, MA | 1 |
| | Solar | Base-load | 2 |
| |
| Solar Connecticut | New England | Various, CT | 1 |
| | Solar | Base-load | 1 |
| |
| Mystic 8, 9 | New England | Charlestown, MA | 6 |
| | Gas | Intermediate | 1,417 |
| |
| Mystic 7 | New England | Charlestown, MA | 1 |
| | Oil/Gas | Intermediate | 573 |
| (m) |
| Wyman | New England | Yarmouth, ME | 1 |
| 5.9 |
| Oil | Intermediate | 35 |
| (e) |
| West Medway | New England | West Medway, MA | 3 |
| | Oil | Peaking | 123 |
| |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
| Framingham | New England | Framingham, MA | 3 |
| | Oil | Peaking | 31 |
| |
| Mystic Jet | New England | Charlestown, MA | 1 |
| | Oil | Peaking | 9 |
| (m) |
| Total New England | | | | | | | 2,203 |
| |
| | | | | | | | | |
| Nine Mile Point | New York | Scriba, NY | 2 |
| 50.01 |
| Uranium | Base-load | 838 |
| (e)(f) |
| FitzPatrick | New York | Scriba, NY | 1 |
| | Uranium | Base-load | 842 |
| |
| Ginna | New York | Ontario, NY | 1 |
| 50.01 |
| Uranium | Base-load | 288 |
| (e)(f) |
| Solar New York | New York | Bethlehem, NY | 1 |
| | Solar | Base-load | 3 |
| |
| Total New York | | | | | | | 1,971 |
| |
| | | | | | | | | |
| Antelope Valley | Other | Lancaster, CA | 1 |
| | Solar | Base-load | 242 |
| |
| Bluestem | Other | Beaver County, OK | 60 |
| 51 |
| Wind | Base-load | 101 |
| (e)(g)(h) |
| Exelon Wind 4 | Other | Gruver, TX | 38 |
| | Wind | Base-load | 80 |
| |
| Shooting Star | Other | Kiowa County, KS | 65 |
| 51 |
| Wind | Base-load | 53 |
| (e)(g) |
| Albany Green Energy | Other | Albany, GA | 1 |
| 99 |
| Biomass | Base-load | 52 |
| (i) |
| Solar Arizona | Other | Various, AZ | 127 |
| | Solar | Base-load | 46 |
| |
| Bluegrass Ridge | Other | King City, MO | 27 |
| 51 |
| Wind | Base-load | 29 |
| (e)(g) |
| California PV Energy 2 | Other | Various, CA | 89 |
| | Solar | Base-load | 27 |
| |
| Conception | Other | Barnard, MO | 24 |
| 51 |
| Wind | Base-load | 26 |
| (e)(g) |
| Cow Branch | Other | Rock Port, MO | 24 |
| 51 |
| Wind | Base-load | 26 |
| (e)(g) |
| Solar Arizona 2 | Other | Various, AZ | 25 |
| | Solar | Base-load | 23 |
| |
| California PV Energy | Other | Various, CA | 53 |
| | Solar | Base-load | 21 |
| |
| Mountain Home | Other | Glenns Ferry, ID | 20 |
| 51 |
| Wind | Base-load | 21 |
| (e)(g) |
| High Mesa | Other | Elmore Co., ID | 19 |
| 51 |
| Wind | Base-load | 20 |
| (e)(g) |
| Echo 1 | Other | Echo, OR | 21 |
| 50.49 |
| Wind | Base-load | 17 |
| (e)(g) |
| Sacramento PV Energy | Other | Sacramento, CA | 4 |
| 51 |
| Solar | Base-load | 15 |
| (e)(g) |
| Cassia | Other | Buhl, ID | 14 |
| 51 |
| Wind | Base-load | 15 |
| (e)(g) |
| Wildcat | Other | Lovington, NM | 13 |
| 51 |
| Wind | Base-load | 14 |
| (e)(g) |
| Echo 2 | Other | Echo, OR | 10 |
| 51 |
| Wind | Base-load | 10 |
| (e)(g) |
| Exelon Wind 5 | Other | Texhoma, TX | 8 |
| | Wind | Base-load | 10 |
| |
| Exelon Wind 6 | Other | Texhoma, TX | 8 |
| | Wind | Base-load | 10 |
| |
| Exelon Wind 7 | Other | Sunray, TX | 8 |
| | Wind | Base-load | 10 |
| |
| Exelon Wind 8 | Other | Sunray, TX | 8 |
| | Wind | Base-load | 10 |
| |
| Exelon Wind 9 | Other | Sunray, TX | 8 |
| | Wind | Base-load | 10 |
| |
| Exelon Wind 10 | Other | Dumas, TX | 8 |
| | Wind | Base-load | 10 |
| |
| Exelon Wind 11 | Other | Dumas, TX | 8 |
| | Wind | Base-load | 10 |
| |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
| High Plains | Other | Panhandle, TX | 8 |
| 99.5 |
| Wind | Base-load | 10 |
| (e) |
| Solar Georgia 2 | Other | Various, GA | 8 |
| | Solar | Base-load | 10 |
| |
| Tuana Springs | Other | Hagerman, ID | 8 |
| 51 |
| Wind | Base-load | 9 |
| (e)(g) |
| Solar Georgia | Other | Various, GA | 10 |
| | Solar | Base-load | 8 |
| |
| Greensburg | Other | Greensburg, KS | 10 |
| 51 |
| Wind | Base-load | 7 |
| (e)(g) |
| Outback Solar | Other | Christmas Valley, OR | 1 |
| | Solar | Base-load | 6 |
| |
| Echo 3 | Other | Echo, OR | 6 |
| 50.49 |
| Wind | Base-load | 5 |
| (e)(g) |
| Three Mile Canyon | Other | Boardman, OR | 6 |
| 51 |
| Wind | Base-load | 5 |
| (e)(g) |
| Loess Hills | Other | Rock Port, MO | 4 |
| | Wind | Base-load | 5 |
| |
| California PV Energy 3 | Other | Various, CA | 10 |
| | Solar | Base-load | 5 |
| |
| Mohave Sunrise Solar | Other | Fort Mohave, AZ | 1 |
| | Solar | Base-load | 5 |
| |
Denver Airport Solar | Other | Denver, CO | 1 |
| 51 |
| Solar | Base-load | 2 |
| (e)(g) |
| Hillabee | Other | Alexander City, AL | 3 |
| | Gas | Intermediate | 753 |
| |
| Grande Prairie | Other | Alberta, Canada | 1 |
| | Gas | Peaking | 105 |
| |
| SEGS 4, 5, 6 | Other | Boron, CA | 3 |
| 4.2-12.2 |
| Solar | Peaking | 9 |
| (e) |
| Total Other | | | | | | | 1,852 |
| |
| Total | | | | | | | 32,463 |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Station(a) | | Location | | No. of
Units | | Percent Owned(b) | | Primary
Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
| Hillabee | | Alexander City,
AL | | 3 | | | | | Gas | | Intermediate | | 753 | | |
| Mystic 7 | | Charlestown, MA | | 1 | | | | | Oil/Gas | | Intermediate | | 512 | | (m) |
| Wyman 4 | | Yarmouth, ME | | 1 | | | 5.9 | | | Oil | | Intermediate | | 35 | | (f) |
| Grand Prairie | | Alberta, Canada | | 1 | | | | | Gas | | Peaking | | 105 | | |
| West Medway | | West Medway, MA | | 3 | | | | | Oil | | Peaking | | 124 | | |
| West Medway II | | West Medway, MA | | 2 | | | | | Oil/Gas | | Peaking | | 192 | | |
| Framingham | | Framingham, MA | | 3 | | | | | Oil | | Peaking | | 31 | | |
| | | | | | | | | | | | | |
| Mystic Jet | | Charlestown, MA | | 1 | | | | | Oil | | Peaking | | 9 | | (m) |
| Total Other | | | | | | | | | | | | 4,037 | | |
| Total | | | | | | | | | | | | 31,271 | | |
__________
| |
(a) | All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, Salem and Three Mile Island, which are pressurized water reactors. |
| |
(b) | 100%, unless otherwise indicated. |
| |
(c) | Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods. |
| |
(d) | For nuclear stations, capacity reflects the annual mean rating. Fossil stations reflect a summer rating. Wind and solar facilities reflect name plate capacity. |
| |
(e) | Net generation capacity is stated at proportionate ownership share. |
| |
(f) | Reflects Generation’s 50.01% interest in CENG, a joint venture with EDF. For Nine Mile Point, the co-owner owns 18% of Unit 2. Thus, Exelon’s ownership is 50.01% of 82% of Nine Mile Point Unit 2. |
| |
(g) | Reflects the sale of 49% of EGRP to a third party on July 6, 2017. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(h) | EGRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets. |
| |
(i) | Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity. |
| |
(j) | Generation has announced it will permanently cease generation operations at TMI on or about September 30, 2019. See Note 8 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(k) | Generation has agreed to retire and cease generation operations at the Gould Street, Fairless Hills, Eastern, Bethlehem, Southeast Chicago, Notch Cliff, Riverside (unit 8), Westport and Pennsbury units on or before June 1, 2020. |
| |
(l) | Generation plans to retire and cease generation operation at Riverside (unit 7) on or about March 14, 2019. |
| |
(m) | Generation plans to retire and cease generation operation at the Mystic 7 and Mystic Jet units on or about June 1, 2022. |
(a)All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, and Salem, which are pressurized water reactors.
(b)100%, unless otherwise indicated.
(c)Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are plants with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods.
(d)For nuclear stations, capacity reflects the annual mean rating. Fossil stations and wind and solar facilities reflect a summer rating.
(e)Generation has announced it will permanently cease generation operations at Byron and Dresden nuclear facilities in 2021 and Mystic Unit 8 and 9 in 2024. See Note 7 — Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information.
(f)Net generation capacity is stated at proportionate ownership share.
(g)Reflects the prior sale of 49% of EGRP to a third party. See Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information.
(h)On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation's solar business. The transaction is expected to be completed in the first half of 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.
(i)Generation has deactivated the site and is evaluating for potential return of service or retirement beyond 2021.
(j)Reflects Generation’s interest in CENG, a joint venture with EDF. See ITEM 1. — BUSINESS — Exelon Generation Company, LLC — Nuclear Facilities for additional information.
(k)EGRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets.
(l)Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity.
(m)Generation has plans to retire and cease plant operations in 2021.
The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies, or generating units being temporarily out of service for inspection, maintenance, refueling, repairs, or modifications required by regulatory authorities.
Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding nuclear insurance of generating facilities, see ITEM 1. BUSINESS — Exelon Generation Company, LLC. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in Generation’s consolidated financial condition or results of operations.
The Utility Registrants
The Utility Registrants' electric substations and a portion of itstheir transmission rights of way are located on property that ComEd owns.they own. A significant portion of itstheir electric transmission and distribution facilities isare located above or underneath highways, streets, other public places, or property that others own. ComEd believesThe Utility Registrants believe that it hasthey have satisfactory rights to use those places or property in the form of permits, grants, easements, licenses, and franchise rights; however, it hasthey have not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
ComEd’sThe Utility Registrants’ high voltage electric transmission lines owned and in service at December 31, 20182020 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Voltage | | Circuit Miles | |
| (Volts) | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | |
| 765,000 | | 90 | | — | | — | | — | | — | | — | |
500,000(a) | | — | | 188 | (a) | 216 | | 109 | | 16 | (a) | — | (a) |
| 345,000 | | 2,676 | | — | | — | | — | | — | | — | |
| 230,000 | | — | | 549 | | 358 | | 770 | | 472 | | 274 | |
| 138,000 | | 2,245 | | 135 | | 55 | | 61 | | 586 | | 214 | |
| 115,000 | | — | | — | | 712 | | 25 | | — | | — | |
| 69,000 | | — | | 177 | | — | | — | | 567 | | 667 | |
|
| | |
| Voltage (Volts) | | Circuit Miles |
| 765,000 | | 90 |
| 345,000 | | 2,716 |
| 138,000 | | 2,209 |
ComEd’s(a) In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 9 - Jointly Owned Electric Utility Plant - for additional information.
The Utility Registrants' electric distribution system includes 35,398the following number of circuit miles of overhead lines and 32,010 circuitunderground lines:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Circuit Miles | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
| Overhead | | 35,379 | | 12,967 | | 9,179 | | 4,082 | | 6,007 | | 7,393 |
| Underground | | 32,349 | | 9,463 | | 17,650 | | 6,949 | | 6,360 | | 2,984 |
Gas
The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2020:
| | | | | | | | | | | | | | | | | | | | |
| PECO | | BGE | | DPL | |
| Transmission | 9 | | 152 | | 8 | (a) |
| Distribution | 6,946 | | 7,443 | | 2,142 | |
| Service piping | 6,449 | | 6,383 | | 1,461 | |
| Total | 13,404 | | 13,978 | | 3,611 | |
___________
(a) DPL has a 10% undivided interest in approximately 8 miles of underground lines.natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities.
The following table presents PECO’s, BGE’s, and DPL’s natural gas facilities:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant | | Facility | | Location | | Storage Capacity
(mmcf) | | Send-out or Peaking Capacity
(mmcf/day) |
| PECO | | LNG Facility | | West Conshohocken, PA | | 1,200 | | 160 |
| PECO | | Propane Air Plant | | Chester, PA | | 105 | | 25 |
| BGE | | LNG Facility | | Baltimore, MD | | 1,056 | | 332 |
| BGE | | Propane Air Plant | | Baltimore, MD | | 550 | | 85 |
| DPL | | LNG Facility | | Wilmington, DE | | 250 | | 25 |
PECO, BGE, and DPL also own 30, 30, and 10 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout their gas service territory, respectively.
First Mortgage and Insurance
The principal properties of ComEd, PECO, PEPCO, DPL, and ACE are subject to the lien of ComEd’s Mortgage dated July 1, 1923, as amended and supplemented,their respective Mortgages under which ComEd’stheir respective First Mortgage Bonds are issued. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
ComEd maintains
The Utility Registrants maintain property insurance against loss or damage to itstheir properties by fire or other perils, subject to certain exceptions. For itstheir insured losses, ComEd isthe Utility Registrants are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of ComEd.the Utility Registrants.
PECO
PECO’s electric substations and a significant portion of its transmission lines are located on property that PECO owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. PECO believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
PECO’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | | |
| Voltage (Volts) | | Circuit Miles | |
| 500,000 | | 188 | (a) |
| 230,000 | | 549 | |
| 138,000 | | 135 | |
| 69,000 | | 181 | |
__________
| |
(a) | In addition, PECO has a 22.00% ownership interest in 127 miles of 500 kV lines located in Pennsylvania and a 42.55% ownership interest in 131 miles of 500 kV lines located in Delaware and New Jersey. |
PECO’s electric distribution system includes 12,957 circuit miles of overhead lines and 9,367 circuit miles of underground lines.
Gas
The following table sets forth PECO’s natural gas pipeline miles at December 31, 2018:
|
| | |
| Pipeline Miles |
Transmission | 9 |
|
Distribution | 6,912 |
|
Service piping | 6,377 |
|
Total | 13,298 |
|
PECO has an LNG facility located in West Conshohocken, Pennsylvania that has a storage capacity of 1,200 mmcf and a send-out capacity of 160 mmcf/day and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 105 mmcf and a peaking capability of 25 mmcf/day. In addition, PECO owns 30 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout its gas service territory.
First Mortgage and Insurance
The principal properties of PECO are subject to the lien of PECO’s Mortgage dated May 1, 1923, as amended and supplemented, under which PECO’s first and refunding mortgage bonds are issued.
PECO maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, PECO is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of PECO.
BGE
BGE’s electric substations and a significant portion of its transmission lines are located on property that BGE owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. BGE believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
BGE’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | |
| Voltage (Volts) | | Circuit Miles |
| 500,000 | | 218 |
| 230,000 | | 358 |
| 138,000 | | 55 |
| 115,000 | | 706 |
BGE’s electric distribution system includes 9,191 circuit miles of overhead lines and 17,295 circuit miles of underground lines.
Gas
The following table sets forth BGE’s natural gas pipeline miles at December 31, 2018:
|
| | |
| Pipeline Miles |
Transmission | 161 |
|
Distribution | 7,348 |
|
Service piping | 6,305 |
|
Total | 13,814 |
|
BGE has an LNG facility located in Baltimore, Maryland that has a storage capacity of 1,056 mmcf and a send-out capacity of 332 mmcf/day and a propane-air plant located in Baltimore, Maryland, with a storage capacity of 550 mmcf and a send-out capacity of 85 mmcf/day. In addition, BGE owns 12 natural gas city gate stations and 20 direct pipeline customer delivery points at various locations throughout its gas service territory.
Property Insurance
BGE owns its principal headquarters building located in downtown Baltimore. BGE maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, BGE is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of BGE.
Pepco
Pepco’s electric substations and a significant portion of its transmission lines are located on property that Pepco owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. Pepco believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
Pepco’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | |
| Voltage (Volts) | | Circuit Miles |
| 500,000 | | 142 |
| 230,000 | | 767 |
| 138,000 | | 61 |
| 115,000 | | 38 |
Pepco’s electric distribution system includes approximately 4,127 circuit miles of overhead lines and 7,039 circuit miles of underground lines. Pepco also operates a distribution system control center in Bethesda, Maryland. The computer equipment and systems contained in Pepco’s control center are financed through a sale and leaseback transaction.
First Mortgage and Insurance
The principal properties of Pepco are subject to the lien of Pepco’s mortgage dated July 1, 1935, as amended and supplemented, under which Pepco First Mortgage Bonds are issued.
Pepco maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, Pepco is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of Pepco.
DPL
DPL’s electric substations and a significant portion of its transmission lines are located on property that DPL owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. DPL believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
DPL’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows: |
| | |
| Voltage (Volts) | | Circuit Miles |
| 500,000 | | 16 |
| 230,000 | | 471 |
| 138,000 | | 586 |
| 69,000 | | 569 |
DPL’s electric distribution system includes approximately 6,031 circuit miles of overhead lines and 6,298 circuit miles of underground lines. DPL also owns and operates a distribution system control center in New Castle, Delaware.
Gas
The following table sets forth DPL’s natural gas pipeline miles at December 31, 2018:
|
| | |
| Pipeline Miles |
Transmission (a)
| 8 |
|
Distribution | 2,065 |
|
Service piping | 1,398 |
|
Total | 3,471 |
|
___________
| |
(a) | DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities. |
DPL owns a liquefied natural gas facility located in Wilmington, Delaware, with a storage capacity of approximately 250 mmcf and an emergency sendout capability of 36 mmcf/day. DPL owns 4 natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary delivery point contractual entitlement of 158 mmcf/day.
First Mortgage and Insurance
The principal properties of DPL are subject to the lien of DPL’s mortgage dated October 1, 1947, as amended and supplemented, under which DPL First Mortgage Bonds are issued.
DPL maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, DPL is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of DPL.
ACE
ACE’s electric substations and a significant portion of its transmission lines are located on property that ACE owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. ACE believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
ACE’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | |
| Voltage (Volts) | | Circuit Miles |
| 500,000 | | — |
| 230,000 | | 221 |
| 138,000 | | 239 |
| 69,000 | | 663 |
ACE’s electric distribution system includes approximately 7,378 circuit miles of overhead lines and 2,927 circuit miles of underground lines. ACE also owns and operates a distribution system control center in Mays Landing, New Jersey.
First Mortgage and Insurance
The principal properties of ACE are subject to the lien of ACE’s mortgage dated January 15, 1937, as amended and supplemented, under which ACE First Mortgage Bonds are issued.
ACE maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, ACE is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of ACE.
Exelon
Security Measures
The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes, and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.
All Registrants
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Note 43 — Regulatory Matters and Note 2219 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.
|
| | | | |
| ITEM 4. | MINE SAFETY DISCLOSURES |
All Registrants
Not Applicable to the Registrants.
PART II
(Dollars in millions except per share data, unless otherwise noted)
|
| | | | |
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Exelon
Exelon’s common stock is listed on the New York Stock ExchangeNasdaq (trading symbol: EXC). As of January 31, 2019,2021, there were 969,745,933976,337,799 shares of common stock outstanding and approximately 99,85791,240 record holders of common stock.
Stock Performance Graph
The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 20142016 through 2018.2020.
This performance chart assumes:
•$100 invested on December 31, 20132015 in Exelon common stock, in the S&P 500 Stock Index, and in the S&P Utility Index; and
•All dividends are reinvested.
| | | Value of Investment at December 31, | Value of Investment at December 31, | Value of Investment at December 31, |
| | 2013 | 2014 | 2015 | 2016 | 2017 | 2018 | | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 |
| Exelon Corporation | $100 | $140.61 | $109.44 | $145.34 | $167.22 | $197.86 | Exelon Corporation | $100 | $132.81 | $152.79 | $180.80 | $188.53 | $181.20 |
| S&P 500 | $100 | $113.68 | $115.24 | $129.02 | $157.17 | $150.27 | S&P 500 | $100 | $111.96 | $136.40 | $130.42 | $171.49 | $203.04 |
| S&P Utilities | $100 | $128.98 | $122.73 | $142.72 | $160.00 | $166.57 | S&P Utilities | $100 | $116.29 | $130.36 | $135.72 | $171.48 | $172.31 |
Generation
As of January 31, 2019,2021, Exelon indirectly held the entire membership interest in Generation.
ComEd
As of January 31, 2019,2021, there were 127,021,331127,021,370 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 31, 2019,2021, in addition to Exelon, there were 294286 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.
PECO
As of January 31, 2019,2021, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon.
BGE
As of January 31, 2019,2021, there were 1,000 outstanding shares of common stock, without par value, of BGE, all of which were indirectly held by Exelon.
PHI
As of January 31, 2019,2021, Exelon indirectly held the entire membership interest in PHI.
Pepco
As of January 31, 2019,2021, there were 100 outstanding shares of common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon.
DPL
As of January 31, 2019,2021, there were 1,000 outstanding shares of common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon.
ACE
As of January 31, 2019,2021, there were 8,546,017 outstanding shares of common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon.
All Registrants
Dividends
Under applicable Federal law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to Exelon.
ComEd has agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its
guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.
Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the DPSC and MDPSC or (b) DPL’s
senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.
Exelon’s Board of Directors approved an updated dividend policy providing an increasefor 2021. The 2021 quarterly dividend will remain the same as the 2020 dividend of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.$0.3825 per share.
At December 31, 2018,2020, Exelon had retained earnings of $14,766$16,735 million, including Generation’s undistributed earnings of $3,724$2,805 million, ComEd’s retained earnings of $1,337$1,456 million consisting of retained earnings appropriated for future dividends of $2,976$3,095 million, partially offset by $1,639 million of unappropriated accumulated deficits, PECO’s retained earnings of $1,242$1,519 million, BGE’s retained earnings of $1,640$1,879 million, and PHI's undistributed earningslosses of $62$68 million.
The following table sets forth Exelon’s quarterly cash dividends per share paid during 20182020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 |
| (per share) | Fourth
Quarter | | Third
Quarter | | Second
Quarter | | First
Quarter | | Fourth
Quarter | | Third
Quarter | | Second
Quarter | | First
Quarter |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Exelon | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3625 | | | $ | 0.3625 | | | $ | 0.3625 | | | $ | 0.3625 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 |
| (per share) | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter |
| Exelon | 0.345 |
| | 0.345 |
| | 0.345 |
| | 0.345 |
| | 0.328 |
| | 0.328 |
| | 0.328 |
| | 0.328 |
|
The following table sets forth Generation's and PHI's quarterly distributions and ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's quarterly common dividend payments:
| | | | 2018 | | 2017 | | 2020 | | 2019 |
| (in millions) | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | (in millions) | 4th
Quarter | | 3rd
Quarter | | 2nd
Quarter | | 1st
Quarter | | 4th
Quarter | | 3rd
Quarter | | 2nd
Quarter | | 1st
Quarter |
| Generation | $ | 313 |
| | $ | 311 |
| | $ | 189 |
| | $ | 188 |
| | $ | 165 |
| | $ | 164 |
| | $ | 166 |
| | $ | 164 |
| Generation | $ | 328 | | | $ | 469 | | | $ | 469 | | | $ | 468 | | | $ | 225 | | | $ | 225 | | | $ | 224 | | | $ | 225 | |
| ComEd | 114 |
| | 116 |
| | 115 |
| | 114 |
| | 106 |
| | 105 |
| | 106 |
| | 105 |
| ComEd | 126 | | | 124 | | | 124 | | | 125 | | | 128 | | | 126 | | | 127 | | | 127 | |
| PECO | 6 |
| | 7 |
| | 6 |
| | 287 |
| | 72 |
| | 72 |
| | 72 |
| | 72 |
| PECO | 85 | | | 85 | | | 85 | | | 85 | | | 90 | | | 88 | | | 90 | | | 90 | |
| BGE | 52 |
| | 52 |
| | 53 |
| | 52 |
| | 50 |
| | 49 |
| | 50 |
| | 49 |
| BGE | 60 | | | 62 | | | 62 | | | 62 | | | 55 | | | 57 | | | 56 | | | 56 | |
| PHI | 94 |
| | 123 |
| | 38 |
| | 71 |
| | 44 |
| | 136 |
| | 62 |
| | 69 |
| PHI | 102 | | | 183 | | | 134 | | | 134 | | | 97 | | | 213 | | | 88 | | | 128 | |
| Pepco | 41 |
| | 78 |
| | 25 |
| | 25 |
| | — |
| | 75 |
| | 28 |
| | 30 |
| Pepco | 58 | | | 73 | | | 73 | | | 28 | | | 40 | | | 101 | | | 48 | | | 24 | |
| DPL | 38 |
| | 18 |
| | 4 |
| | 36 |
| | 30 |
| | 28 |
| | 24 |
| | 30 |
| DPL | 42 | | | 33 | | | 14 | | | 52 | | | 34 | | | 35 | | | 29 | | | 41 | |
| ACE | 13 |
| | 27 |
| | 10 |
| | 9 |
| | 15 |
| | 31 |
| | 12 |
| | 10 |
| ACE | 3 | | | 76 | | | 12 | | | 23 | | | 24 | | | 76 | | | 12 | | | 12 | |
First Quarter 20192021 Dividend
On February 5, 2019, the Exelon21, 2021, Exelon's Board of Directors declared a first quarter 2019 regular quarterly dividend of $0.3625$0.3825 per share on Exelon’s common stock for the first quarter of 2021. The dividend is payable on Monday, March 8, 2019,15, 2021, to shareholders of record of Exelon at the endas of the day5 p.m. Eastern time on February 20, 2019.
Monday, March 8, 2021.
|
| | | | |
ITEM 6. | SELECTED FINANCIAL DATA |
Exelon
The selected financial data presented below has been derived from the audited consolidated financial statements of Exelon. This data is qualified in its entirety by reference to and should be read in conjunction with Exelon’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions, except per share data) | 2018 | | 2017(c, d) | | 2016(a, c, d) | | 2015(c) | | 2014(b,c) |
| Statement of Operations data: | | | | | | | | | |
| Operating revenues | $ | 35,985 |
| | $ | 33,565 |
| | $ | 31,366 |
| | $ | 29,447 |
| | $ | 27,429 |
|
| Operating income | 3,898 |
| | 4,395 |
| | 3,212 |
| | 4,554 |
| | 3,210 |
|
| Net income | 2,084 |
|
| 3,876 |
|
| 1,196 |
|
| 2,250 |
|
| 1,820 |
|
| Net income attributable to common shareholders | 2,010 |
| | 3,786 |
| | 1,121 |
| | 2,269 |
| | 1,623 |
|
| Earnings per average common share (diluted): | | | | | | | | | |
| Net income | $ | 2.07 |
| | $ | 3.99 |
| | $ | 1.21 |
| | $ | 2.54 |
| | $ | 1.88 |
|
| Dividends per common share | $ | 1.38 |
| | $ | 1.31 |
| | $ | 1.26 |
| | $ | 1.24 |
| | $ | 1.24 |
|
__________
| |
(a) | The 2016 financial results include the activity of PHI from the merger effective date of March 24, 2016 through December 31, 2016. |
| |
(b) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis. |
| |
(c) | Amounts have been recasted to reflect the Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.
|
| |
(d) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative. |
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017(a) | | 2016(a) | | 2015(a) | | 2014(a) |
| Balance Sheet data: | | | | | | | | | |
| Current assets | $ | 13,360 |
| | $ | 11,896 |
| | $ | 12,451 |
| | $ | 15,334 |
| | $ | 11,853 |
|
| Property, plant and equipment, net | 76,707 |
| | 74,202 |
| | 71,555 |
| | 57,439 |
| | 52,170 |
|
| Total assets | 119,666 |
|
| 116,770 |
|
| 114,952 |
|
| 95,384 |
|
| 86,416 |
|
| Current liabilities | 11,404 |
| | 10,798 |
| | 13,463 |
| | 9,118 |
| | 8,762 |
|
| Long-term debt, including long-term debt to financing trusts | 34,465 |
| | 32,565 |
| | 32,216 |
| | 24,286 |
| | 19,853 |
|
| Shareholders’ equity | 30,764 |
| | 29,896 |
| | 25,860 |
| | 25,793 |
| | 22,608 |
|
| |
(a) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative.
|
Generation
The selected financial data presented below has been derived from the audited consolidated financial statements of Generation. This data is qualified in its entirety by reference to and should be read in conjunction with Generation’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017(b) | | 2016(b) | | 2015 | | 2014(a) |
| Statement of Operations data: | | | | | | | | | |
| Operating revenues | $ | 20,437 |
| | $ | 18,500 |
| | $ | 17,757 |
| | $ | 19,135 |
| | $ | 17,393 |
|
| Operating income | 975 |
| | 947 |
| | 820 |
| | 2,275 |
| | 1,176 |
|
| Net income | 443 |
| | 2,798 |
| | 550 |
| | 1,340 |
| | 1,019 |
|
__________
| |
(a) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis. |
| |
(b) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative.
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017(a) | | 2016(a) | | 2015 | | 2014 |
| Balance Sheet data: | | | | | | | | | |
| Current assets | $ | 8,433 |
| | $ | 6,882 |
| | $ | 6,567 |
| | $ | 6,342 |
| | $ | 7,311 |
|
| Property, plant and equipment, net | 23,981 |
| | 24,906 |
| | 25,585 |
| | 25,843 |
| | 23,028 |
|
| Total assets | 47,556 |
|
| 48,457 |
|
| 47,022 |
|
| 46,529 |
|
| 44,951 |
|
| Current liabilities | 5,769 |
| | 4,191 |
| | 5,689 |
| | 4,933 |
| | 4,459 |
|
| Long-term debt, including long-term debt to affiliates | 7,887 |
| | 8,644 |
| | 8,124 |
| | 8,869 |
| | 7,582 |
|
| Member’s equity | 13,204 |
| | 13,669 |
| | 11,505 |
| | 11,635 |
| | 12,718 |
|
| |
(a) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative.
|
ComEd
The selected financial data presented below has been derived from the audited consolidated financial statements of ComEd. This data is qualified in its entirety by reference to and should be read in conjunction with ComEd’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| Statement of Operations data: | | | | | | | | | |
| Operating revenues | $ | 5,882 |
| | $ | 5,536 |
| | $ | 5,254 |
| | $ | 4,905 |
| | $ | 4,564 |
|
| Operating income | 1,146 |
| | 1,323 |
| | 1,205 |
| | 1,017 |
| | 980 |
|
| Net income | 664 |
| | 567 |
| | 378 |
| | 426 |
| | 408 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| Balance Sheet data: | | | | | | | | | |
| Current assets | $ | 1,570 |
| | $ | 1,364 |
| | $ | 1,554 |
| | $ | 1,518 |
| | $ | 1,723 |
|
| Property, plant and equipment, net | 22,058 |
| | 20,723 |
| | 19,335 |
| | 17,502 |
| | 15,793 |
|
| Total assets | 31,213 |
|
| 29,726 |
|
| 28,335 |
|
| 26,532 |
|
| 25,358 |
|
| Current liabilities | 1,925 |
| | 2,294 |
| | 2,938 |
| | 2,766 |
| | 1,923 |
|
| Long-term debt, including long-term debt to financing trusts | 8,006 |
| | 6,966 |
| | 6,813 |
| | 6,049 |
| | 5,870 |
|
| Shareholders’ equity | 10,247 |
| | 9,542 |
| | 8,725 |
| | 8,243 |
| | 7,907 |
|
PECO
The selected financial data presented below has been derived from the audited consolidated financial statements of PECO. This data is qualified in its entirety by reference to and should be read in conjunction with PECO’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| Statement of Operations data: | | | | | | | | | |
| Operating revenues | $ | 3,038 |
| | $ | 2,870 |
| | $ | 2,994 |
| | $ | 3,032 |
| | $ | 3,094 |
|
| Operating income | 587 |
| | 655 |
| | 702 |
| | 630 |
| | 572 |
|
| Net income | 460 |
| | 434 |
| | 438 |
| | 378 |
| | 352 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| Balance Sheet data: | | | | | | | | | |
| Current assets | $ | 782 |
| | $ | 822 |
| | $ | 757 |
| | $ | 842 |
| | $ | 645 |
|
| Property, plant and equipment, net | 8,610 |
| | 8,053 |
| | 7,565 |
| | 7,141 |
| | 6,801 |
|
| Total assets | 10,642 |
|
| 10,170 |
|
| 10,831 |
|
| 10,367 |
|
| 9,860 |
|
| Current liabilities | 809 |
| | 1,267 |
| | 727 |
| | 944 |
| | 653 |
|
| Long-term debt, including long-term debt to financing trusts | 3,268 |
| | 2,587 |
| | 2,764 |
| | 2,464 |
| | 2,416 |
|
| Shareholder's equity | 3,820 |
| | 3,577 |
| | 3,415 |
| | 3,236 |
| | 3,121 |
|
BGE
The selected financial data presented below has been derived from the audited consolidated financial statements of BGE. This data is qualified in its entirety by reference to and should be read in conjunction with BGE’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| Statement of Operations data: | | | | | | | | | |
| Operating revenues | $ | 3,169 |
| | $ | 3,176 |
| | $ | 3,233 |
| | $ | 3,135 |
| | $ | 3,165 |
|
| Operating income | 474 |
| | 614 |
| | 550 |
| | 558 |
| | 439 |
|
| Net income | 313 |
| | 307 |
| | 294 |
| | 288 |
| | 211 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| Balance Sheet data: | | | | | | | | | |
| Current assets | $ | 786 |
| | $ | 811 |
| | $ | 842 |
| | $ | 845 |
| | $ | 951 |
|
| Property, plant and equipment, net | 8,243 |
| | 7,602 |
| | 7,040 |
| | 6,597 |
| | 6,204 |
|
| Total assets | 9,716 |
|
| 9,104 |
|
| 8,704 |
|
| 8,295 |
|
| 8,056 |
|
| Current liabilities | 774 |
| | 760 |
| | 707 |
| | 1,134 |
| | 794 |
|
| Long-term debt, including long-term debt to financing trusts | 2,876 |
| | 2,577 |
| | 2,533 |
| | 1,732 |
| | 2,109 |
|
| Shareholder's equity | 3,354 |
| | 3,141 |
| | 2,848 |
| | 2,687 |
| | 2,563 |
|
PHI
The selected financial data presented below has been derived from the audited consolidated financial statements of PHI. This data is qualified in its entirety by reference to and should be read in conjunction with PHI’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the Years Ended
December 31, | | March 24 to December 31 | | | January 1 to March 23, | | For the Years Ended
December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | | | |
| Operating revenues | $ | 4,805 |
| | $ | 4,679 |
| | $ | 3,643 |
| | | $ | 1,153 |
| | $4,935 | | $ | 4,808 |
|
| Operating income | 650 |
| | 769 |
| | 93 |
| | | 105 |
| | 673 |
| | 605 |
|
| Net income (loss) from continuing operations | 398 |
| | 362 |
| | (61 | ) | | | 19 |
| | 318 |
| | 242 |
|
| Net income (loss) | 398 |
| | 362 |
| | (61 | ) | | | 19 |
| | 327 |
| | 242 |
|
|
| | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | December 31, | | | December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | | 2015 |
Balance Sheet data(a): | | | | | | | | |
| Current assets | $ | 1,533 |
| | $ | 1,551 |
| | $ | 1,838 |
| | | $ | 1,474 |
|
| Property, plant and equipment, net | 13,446 |
| | 12,498 |
| | 11,598 |
| | | 10,864 |
|
| Total assets | 21,984 |
| | 21,247 |
| | 21,025 |
| | | 16,188 |
|
| Current liabilities | 1,592 |
| | 1,931 |
| | 2,284 |
| | | 2,327 |
|
| Long-term debt | 6,134 |
| | 5,478 |
| | 5,645 |
| | | 4,823 |
|
| Preferred Stock | — |
| | — |
| | — |
| | | 183 |
|
| Member’s equity/Shareholders' equity | 9,282 |
| | 8,825 |
| | 8,016 |
| | | 4,413 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present PHI's selected financial data for the periods reflected above. |
Pepco
The selected financial data presented below has been derived from the audited consolidated financial statements of Pepco. This data is qualified in its entirety by reference to and should be read in conjunction with Pepco’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | |
| Operating revenues | $ | 2,239 |
| | $ | 2,158 |
| | $ | 2,186 |
| | $ | 2,129 |
| | $ | 2,055 |
|
| Operating income | 320 |
| | 399 |
| | 174 |
| | 385 |
| | 349 |
|
| Net income | 210 |
| | 205 |
| | 42 |
| | 187 |
| | 171 |
|
|
| | | | | | | | | | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | 2015 |
Balance Sheet data(a): | | | | | | | |
| Current assets | $ | 760 |
| | $ | 710 |
| | $ | 684 |
| | $ | 726 |
|
| Property, plant and equipment, net | 6,460 |
| | 6,001 |
| | 5,571 |
| | 5,162 |
|
| Total assets | 8,299 |
| | 7,832 |
| | 7,335 |
| | 6,908 |
|
| Current liabilities | 628 |
| | 550 |
| | 596 |
| | 455 |
|
| Long-term debt | 2,704 |
| | 2,521 |
| | 2,333 |
| | 2,340 |
|
| Shareholder's equity | 2,740 |
| | 2,533 |
| | 2,300 |
| | 2,240 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present Pepco's selected financial data for the periods reflected above. |
DPL
The selected financial data presented below has been derived from the audited consolidated financial statements of DPL. This data is qualified in its entirety by reference to and should be read in conjunction with DPL’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | |
| Operating revenues | $ | 1,332 |
| | $ | 1,300 |
| | $ | 1,277 |
| | $ | 1,302 |
| | $ | 1,282 |
|
| Operating income | 190 |
| | 229 |
| | 50 |
| | 165 |
| | 207 |
|
| Net income (loss) | 120 |
| | 121 |
| | (9 | ) | | 76 |
| | 104 |
|
|
| | | | | | | | | | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | 2015 |
Balance Sheet data(a): | | | | | | | |
| Current assets | $ | 336 |
| | $ | 325 |
| | $ | 370 |
| | $ | 388 |
|
| Property, plant and equipment, net | 3,821 |
| | 3,579 |
| | 3,273 |
| | 3,070 |
|
| Total assets | 4,588 |
| | 4,357 |
| | 4,153 |
| | 3,969 |
|
| Current liabilities | 375 |
| | 547 |
| | 381 |
| | 564 |
|
| Long-term debt | 1,403 |
| | 1,217 |
| | 1,221 |
| | 1,061 |
|
| Shareholder's equity | 1,509 |
| | 1,335 |
| | 1,326 |
| | 1,237 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present DPL's selected financial data for the periods reflected above. |
ACE
The selected financial data presented below has been derived from the audited consolidated financial statements of ACE. This data is qualified in its entirety by reference to and should be read in conjunction with ACE’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | |
| Operating revenues | $ | 1,236 |
| | $ | 1,186 |
| | $ | 1,257 |
| | $ | 1,295 |
| | $ | 1,210 |
|
| Operating income | 149 |
| | 157 |
| | 7 |
| | 134 |
| | 137 |
|
| Net income (loss) | 75 |
| | 77 |
| | (42 | ) | | 40 |
| | 46 |
|
|
| | | | | | | | | | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | | 2015 |
Balance Sheet data(a): | | | | | | | |
| Current assets | $ | 240 |
| | $ | 258 |
| | $ | 399 |
| | $ | 546 |
|
| Property, plant and equipment, net | 2,966 |
| | 2,706 |
| | 2,521 |
| | 2,322 |
|
| Total assets | 3,699 |
| | 3,445 |
| | 3,457 |
| | $ | 3,387 |
|
| Current liabilities | 422 |
| | 619 |
| | 320 |
| | $ | 297 |
|
| Long-term debt | 1,170 |
| | 840 |
| | 1,120 |
| | 1,153 |
|
| Shareholder's equity | 1,126 |
| | 1,043 |
| | 1,034 |
| | 1,000 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present ACE's selected financial data for the periods reflected above. |
|
| |
| Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Exelon
Executive Overview
Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
Exelon has twelveeleven reportable segments consisting of Generation’s sixfive reportable segments (Mid-Atlantic, Midwest, New England, New York, ERCOT, and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL, and ACE. During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation will disclose five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. See Note 1 -— Significant Accounting Policies and Note 24 -5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. Additionally, the results of Exelon’s corporate operations include interest costs and income from various investment and financing activities.
Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2020 compared to the year ended December 31, 2019, and is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. For discussion of the year ended December 31, 2019 compared to the year ended December 31, 2018, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2019 Form 10-K, which was filed with the SEC on February 11, 2020.
COVID-19. The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of COVID-19. The Registrants provide a critical service to our customers which means that it is paramount that we keep our employees who operate our businesses safe and minimize unnecessary risk of exposure to the virus. The Registrants have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities. The Registrants have implemented work from home policies where appropriate, and imposed travel limitations on their employees. In addition, the Registrants have updated existing business continuity plans in the context of this pandemic.
The Registrants continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers.
There were no changes in internal control over financial reporting in 2020 as a result of COVID-19 that materially affected, or are reasonably likely to materially affect, any of the Registrants’ internal control over financial reporting. See ITEM 9A. CONTROLS AND PROCEDURES for additional information.
Unfavorable economic conditions due to COVID-19 have impacted the demand for electricity and natural gas at Generation and the Utility Registrants, which has resulted in a decrease in operating revenues.
As a result of COVID-19, Generation temporarily suspended interruption of service for all retail residential customers for non-payment and temporarily ceased new late payment fees for all retail customers from March to May of 2020. Starting in March of 2020, the Utility Registrants also temporarily suspended customer disconnections for non-payment and temporarily ceased new late payment fees for all customers and restored service to customers upon request who were disconnected in the last twelve months. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on such measures at the Utility Registrants. At Generation, such measures resulted in an increase in credit loss expense. ComEd and ACE recorded regulatory assets for the incremental credit loss expense based on existing mechanisms. BGE, PECO, Pepco, and DPL also recorded regulatory assets for substantially all the incremental credit loss expense incurred in 2020. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Generation and the Utility Registrants have also incurred direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of their employees. At Generation and PECO, such costs are recorded as Operating and maintenance expense and are excluded from Adjusted (non-GAAP) Operating Earnings. At ComEd, BGE, Pepco, DPL, and ACE, such costs are primarily recorded as regulatory assets. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The estimated impact to Generation’s and the Utility Registrants’ Net income is approximately $170 million and $75 million for the year ended December 31, 2020, respectively.
To offset the unfavorable impacts from COVID-19, the Registrants identified approximately $250 million in cost savings across Generation and the Utility Registrants in 2020. The cost savings achieved in 2020 were higher than originally anticipated.
The Registrants rely on the capital markets for publicly offered debt as well as the commercial paper markets to meet their financial commitments and short-term liquidity needs. As a result of the disruptions in the commercial paper markets in March of 2020, Generation borrowed $1.5 billion on its revolving credit facility to refinance commercial paper, which Generation repaid on April 3, 2020. Generation also entered into two short-term loan agreements in March of 2020 for an aggregate of $500 million. On April 8, 2020, Generation received approximately $500 million in cash after entering into an accounts receivable financing arrangement. On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility to be used as an additional source of short-term liquidity. In addition, the Registrants issued long-term debt of $5.3 billion and were able to successfully complete their planned long-term debt issuances in 2020. See Liquidity and Capital Resources, Note 17 — Debt and Credit Agreements, and Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants assessed long-lived assets, goodwill, and investments for recoverability and there were no material impairment charges recorded in 2020 as a result of COVID-19. See Note 12 — Asset Impairments for additional information related to other impairment assessments in the third quarter of 2020. Certain assumptions are highly sensitive to changes. Changes in significant assumptions could potentially result in future impairments, which could be material.
This is an evolving situation that could lead to extended disruption of economic activity in our markets. The Registrants will continue to monitor developments affecting their workforce, customers, and suppliers and will take additional precautions that they determine to be necessary in order to mitigate the impacts. The extent to which COVID-19 may impact the Registrants’ ability to operate their generating and transmission and distribution assets, the ability to access capital markets, and results of operations, including demand for electricity and natural gas, will depend on the spread and proliferation of COVID-19 around the world and future developments, which are highly uncertain and cannot be predicted at this time.
Financial Results of Operations
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the year ended December 31, 20182020 compared to the same period in 2017 and December 31, 2017 compared to the same period in 2016.2019. For additional information regarding the financial results for the years ended December 31, 2018, 2017 2020and 20162019 see the discussions of Results of Operations by Registrant.
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
| Exelon | $ | 2,010 |
| | $ | 3,786 |
| | $ | (1,776 | ) | | $ | 1,121 |
| | $ | 2,665 |
|
| Generation | 370 |
| | 2,710 |
| | (2,340 | ) | | 483 |
| | 2,227 |
|
| ComEd | 664 |
| | 567 |
| | 97 |
| | 378 |
| | 189 |
|
| PECO | 460 |
| | 434 |
| | 26 |
| | 438 |
| | (4 | ) |
| BGE | 313 |
| | 307 |
| | 6 |
| | 286 |
| | 21 |
|
| Pepco | 210 |
| | 205 |
| | 5 |
| | 42 |
| | 163 |
|
| DPL | 120 |
| | 121 |
| | (1 | ) | | (9 | ) | | 130 |
|
| ACE | 75 |
| | 77 |
| | (2 | ) | | (42 | ) | | 119 |
|
Other(b) | (195 | ) | | (594 | ) | | 399 |
| | (422 | ) | | (172 | ) |
|
| | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the Years Ended December 31, | | Favorable (unfavorable) 2018 vs. 2017 variance | | March 24 to December 31, | | | January 1 to
March 23, |
| | 2018 | | 2017 | | | 2016 | | | 2016 |
PHI(a) | $ | 398 |
| | $ | 362 |
| | $ | 36 |
| | $ | (61 | ) | | | $ | 19 |
|
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | (Unfavorable) Favorable Variance |
| Exelon | $ | 1,963 | | | $ | 2,936 | | | $ | (973) | |
| Generation | 589 | | | 1,125 | | | (536) | |
| ComEd | 438 | | | 688 | | | (250) | |
| PECO | 447 | | | 528 | | | (81) | |
| BGE | 349 | | | 360 | | | (11) | |
| PHI | 495 | | | 477 | | | 18 | |
| Pepco | 266 | | | 243 | | | 23 | |
| DPL | 125 | | | 147 | | | (22) | |
| ACE | 112 | | | 99 | | | 13 | |
Other(a) | (355) | | | (242) | | | (113) | |
__________
| |
(a) | Includes the consolidated results of Pepco, DPL and ACE. |
| |
(b) | Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities. |
(a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities.
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017.2019. Net income attributable to common shareholdersdecreased by $1,776$973 million and diluted earnings per average common share decreased to $2.07$2.01 in 20182020 from $3.99$3.01 in 20172019 primarily due to:
Impacts•One-time charges and accelerated depreciation and amortization associated with Generation's decisions in the one-time remeasurementthird quarter of deferred income taxes2020 to early retire Byron and Dresden nuclear facilities in 2017 as a result2021 and Mystic Units 8 and 9 in 2024, partially offset by the absence of the TCJA;
Net unrealized losses on NDT funds in 2018 compared to net gains in 2017;
Lower realized energy prices;
Acceleratedaccelerated depreciation and amortization due to the decisionearly retirement of TMI in September 2019;
•Impairment of the New England asset group;
•Payments that ComEd made under the Deferred Prosecution Agreement. See Note 19 — Commitments and Contingencies of the Combined Notes to early retireConsolidated Financial Statements for additional information;
•Lower capacity revenue;
•Reduction in load due to COVID-19 at Generation;
•Lower realized energy prices;
•Higher nuclear outage days;
•Impact of Generation's annual update to the Oyster Creeknuclear ARO for Non-Regulatory Agreement Units;
•Lower net unrealized and TMI nuclear facilities;realized gains on NDT funds;
The gain associated with the FitzPatrick acquisition•COVID-19 direct costs;
•Lower electric distribution earnings from lower allowed ROE due to a decrease in 2017;treasury rates, partially offset by higher rate base at ComEd;
Decrease in reserves for uncertain tax positions in 2017
•Higher storm costs related to the deductibility of certain merger commitments associated with the 2012 ConstellationJune 2020 and 2016 PHI acquisitions;
Increased mark-to-market losses;
The gain recorded upon deconsolidation of EGTP's net liabilities in 2017;
The absence of EGTP earnings resulting from its deconsolidation in the fourth quarter of 2017;
Long-lived asset impairments of certain merchant wind assets in West Texas; and
Increased storm costsAugust 2020 storms at PECO, net of tax repairs, and BGE.related to the August 2020 storm at DPL;
•Unfavorable weather conditions at PECO, DPL Delaware, and ACE; and
•A net increase in depreciation and amortization expense due to ongoing capital expenditures at PECO, BGE, Pepco, DPL, and ACE, partially offset at Generation due to the impact of extending the operating license at Peach Bottom.
The decreases were partially offset by;
The impact•Higher mark-to-market gains;
•Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter and were fair valued based on quoted market prices of the New York and Illinois ZEC revenue (including the impactstocks as of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017);2020;
Long-lived asset impairments•Lower operating and maintenance expense at Generation primarily related to the EGTP assets held for sale in 2017;
Increased capacity prices;
The impact of lower federal income tax rate as a result of the TCJA at Generation;
Net realized gains on NDT funds;
The gain on the settlement of a long-term gas supply agreement;
Decreased nuclear outage days;
Increased electric distribution and energy efficiency formula rate earnings at ComEd;
Regulatory rate increases at PECO, BGE and PHI;
The impact of favorable weather at PECO, DPL and ACE; and
The absences of a 2017 impairment of certain transmission-related income tax regulatory assets at ComEd, BGE and PHI.
The decrease in diluted earnings per share was also due to the increase in Exelon’s average diluted shares outstanding as a result of the June 2017 common stock issuance.previous cost management programs, lower contracting costs, and lower travel costs, partially offset by lower NEIL insurance distributions;
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. Net income attributable to common shareholdersincreased by $2,665 million and diluted earnings per average common share increased to $3.99 in 2017 from $1.21 in 2016 primarily due to:•Lower nuclear fuel costs;
Impacts associated with the one-time remeasurement of deferred income taxes as a result of the TCJA;
The gain associated with the FitzPatrick acquisition;
Accelerated depreciation and amortization due to the decision to early retire the TMI nuclear facility in 2017 compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities;
Higher net unrealized and realized gains on NDT funds;
The impact of the New York ZEC revenue;
The gain recorded upon deconsolidation of EGTP's net liabilities;
Increased capacity prices;
Decreased nuclear outage days;
Decrease in reserves for uncertain•A tax positions in 2017 related to the deductibility of certain merger commitments associated with the 2012 Constellation and 2016 PHI acquisitions compared to costs incurred as part of the settlement orders approving the PHI acquisition and a chargebenefit related to a 2012 CEG merger commitmentsettlement in 2016;the first quarter of 2020, partially offset by the absence of a tax benefit related to certain research and development activities recorded in the fourth quarter of 2019 at Generation;and
Increased electric distribution and transmission formula rate earnings at ComEd;
•Regulatory rate increases at BGE, and PHI; and
Penalties and associated interest expense as a result of a tax court decision on Exelon's like-kind exchange position in 2016.
The increases were partially offset by;
Long-lived asset impairments primarily related to the EGTP assets held for sale;
Lower realized energy prices;
The conclusion of the Ginna Reliability Support Services Agreement;
Increased costs related to the acquisition of the FitzPatrick nuclear facility;
Increased mark-to-market losses;
The impact of unfavorable weather at ComEd, PECO, DPL, and ACE; andACE.
The impairment of certain transmission-related income tax regulatory assets at ComEd, BGE and PHI.
The net increase in diluted earnings per share from the items listed above was partially offset by the impact of the increase in Exelon’s average diluted shares outstanding as a result of the June 2017 common stock issuance.
Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
The following table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 20182020 as compared to 2017 and 2016:2019:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| (All amounts after tax; in millions, except per share amounts) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share | | | | Earnings per Diluted Share |
| Net Income Attributable to Common Shareholders | $ | 2,010 |
| | $ | 2.07 |
| | $ | 3,786 |
| | $ | 3.99 |
| | $ | 1,121 |
| | $ | 1.21 |
|
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $89, $68 and $18, respectively) | 252 |
| | 0.26 |
| | 107 |
| | 0.11 |
| | 24 |
| | 0.03 |
|
Unrealized Losses (Gains) Related to NDT Funds(b) (net of taxes of $289, $286 and $112, respectively) | 337 |
| | 0.35 |
| | (318 | ) | | (0.34 | ) | | (118 | ) | | (0.13 | ) |
Amortization of Commodity Contract Intangibles(c) (net of taxes of $0, $22 and $22, respectively) | — |
| | — |
| | 34 |
| | 0.04 |
| | 35 |
| | 0.04 |
|
Merger and Integration Costs(d) (net of taxes of $2, $25 and $50, respectively) | 3 |
| | — |
| | 40 |
| | 0.04 |
| | 114 |
| | 0.12 |
|
Merger Commitments(e) (net of taxes of $0, $137 and $126, respectively) | — |
| | — |
| | (137 | ) | | (0.14 | ) | | 437 |
| | 0.47 |
|
Long-Lived Asset Impairments(f) (net of taxes of $13, $204 and $68, respectively) | 35 |
| | 0.04 |
| | 321 |
| | 0.34 |
| | 103 |
| | 0.11 |
|
Plant Retirements and Divestitures(g) (net of taxes of $181, $134 and $273, respectively) | 512 |
| | 0.53 |
| | 207 |
| | 0.22 |
| | 432 |
| | 0.47 |
|
Cost Management Program(h) (net of taxes of $16, $21 and $21, respectively) | 48 |
| | 0.05 |
| | 34 |
| | 0.04 |
| | 34 |
| | 0.04 |
|
Annual Asset Retirement Obligation Update(i) (net of taxes of $7, $1 and $13, respectively) | 20 |
| | 0.02 |
| | (2 | ) | | — |
| | (75 | ) | | (0.08 | ) |
Vacation Policy Change(j) (net of taxes of $0, $21 and $0, respectively) | — |
| | — |
| | (33 | ) | | (0.03 | ) | | — |
| | — |
|
| Change in Environmental Liabilities (net of taxes of $0, $17 and $0, respectively) | (1 | ) | | — |
| | 27 |
| | 0.03 |
| | — |
| | — |
|
Bargain Purchase Gain(k) (net of taxes of $0, $0 and $0, respectively) | — |
| | — |
| | (233 | ) | | (0.25 | ) | | — |
| | — |
|
Gain on Deconsolidation of Business(l) (net of taxes of $0, $83 and $0, respectively) | — |
| | — |
| | (130 | ) | | (0.14 | ) | | — |
| | — |
|
Gain on Contract Settlement(m) (net of taxes of $20, $0 and $0, respectively) | (55 | ) | | (0.06 | ) | | — |
| | — |
| | — |
| | — |
|
Like-Kind Exchange Tax Position(n) (net of taxes of $0, $66 and $61, respectively) | — |
| | — |
| | (26 | ) | | (0.03 | ) | | 199 |
| | 0.21 |
|
Curtailment of Generation Growth and Development Activities(o) (net of taxes of $0, $0 and $35, respectively) | — |
| | — |
| | — |
| | — |
| | 57 |
| | 0.06 |
|
Reassessment of Deferred Income Taxes(p) (entire amount represents tax expense) | (22 | ) | | (0.02 | ) | | (1,299 | ) | | (1.37 | ) | | 10 |
| | 0.01 |
|
Tax Settlements(q) (net of taxes of $0, $1 and $0, respectively) | — |
| | — |
| | (5 | ) | | (0.01 | ) | | — |
| | — |
|
Noncontrolling Interests(r) (net of taxes of $24, $24 and $9, respectively) | (113 | ) | | (0.12 | ) | | 114 |
| | 0.12 |
| | 102 |
| | 0.11 |
|
| Adjusted (non-GAAP) Operating Earnings | $ | 3,026 |
| | $ | 3.12 |
| | $ | 2,487 |
| | $ | 2.62 |
| | $ | 2,475 |
| | $ | 2.67 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| 2020 | | 2019 |
| (All amounts in millions after tax) | | | Earnings per
Diluted Share | | | | Earnings per
Diluted Share |
| Net Income Attributable to Common Shareholders | $ | 1,963 | | | $ | 2.01 | | | $ | 2,936 | | | $ | 3.01 | |
| Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $73 and $66, respectively) | (213) | | | (0.22) | | | 197 | | | 0.20 | |
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $278 and $269, respectively)(a) | (256) | | | (0.26) | | | (299) | | | (0.31) | |
| | | | | | | |
Asset Impairments (net of taxes of $135 and $56, respectively)(b) | 396 | | | 0.41 | | | 123 | | | 0.13 | |
Plant Retirements and Divestitures (net of taxes of $244 and $9, respectively)(c) | 718 | | | 0.74 | | | 118 | | | 0.12 | |
Cost Management Program (net of taxes of $14 and $17, respectively)(d) | 45 | | | 0.05 | | | 51 | | | 0.05 | |
| Litigation Settlement Gain (net of taxes of $7) | — | | | — | | | (19) | | | (0.02) | |
Asset Retirement Obligation (net of taxes of $16 and $9, respectively)(e) | 48 | | | 0.05 | | | (84) | | | (0.09) | |
| Change in Environmental Liabilities (net of taxes of $6 and $8, respectively) | 18 | | | 0.02 | | | 20 | | | 0.02 | |
COVID-19 Direct Costs (net of taxes of $19)(f) | 50 | | | 0.05 | | | — | | | — | |
Deferred Prosecution Agreement Payments (net of taxes of $0)(g) | 200 | | | 0.20 | | | — | | | — | |
Acquisition Related Costs (net of taxes of $1)(h) | 4 | | | — | | | — | | | — | |
ERP System Implementation Costs (net of taxes of $1)(i) | 3 | | | — | | | — | | | — | |
Income Tax-Related Adjustments (entire amount represents tax expense)(j) | 71 | | | 0.07 | | | 5 | | | 0.01 | |
Noncontrolling Interests (net of taxes of $19 and $26, respectively)(k) | 103 | | | 0.11 | | | 90 | | | 0.09 | |
| Adjusted (non-GAAP) Operating Earnings | $ | 3,149 | | | $ | 3.22 | | | $ | 3,139 | | | $ | 3.22 | |
__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT funds, the marginal statutory income tax rates for 2018, 20172020 and 20162019 ranged from 26.0 percent26.0% to 29.0 percent, 39.0 percent to 41.0 percent and 39.0 percent to 41.0 percent, respectively.29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT funds were 46.2 percent, 47.4 percent52.1% and 48.7 percent47.3% for the years ended December 31, 2018, 20172020 and 2016,2019, respectively.
| |
(a) | Reflects the impact of net losses on economic hedging activities. See Note 12 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information related to hedging activities. |
| |
(b) | Reflects the impact of net unrealized gains and losses on Generation’s NDT funds
(a)Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact. |
| |
(c) | Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to, in 2016, the Integrys and ConEdison Solutions acquisitions, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions. |
| |
(d) | Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2016 and 2017, reflects costs related to the PHI and FitzPatrick acquisitions, partially offset in 2016 at ComEd, and in 2017, at PHI, by the anticipated recovery of previously incurred PHI acquisition costs. In 2018, reflects costs related to the PHI acquisition. See Note 5 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(e) | Represents costs incurred as part of the settlement orders approving the PHI acquisition, and in 2016, a charge related to a 2012 CEG merger commitment, and in 2017, primarily a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions. |
| |
(f) | In 2016, primarily reflects the impairment of upstream assets and certain wind projects at Generation. In 2017, primarily reflects the impairment of the EGTP assets held for sale and PHI District of Columbia sponsorship intangible asset. In 2018, primarily reflects the impairment of certain wind projects at Generation. |
| |
(g) | In 2016, primarily reflects accelerated depreciation and amortization expenses through December 2016 and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s sale of the New Boston generating site. In 2017, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the TMI nuclear facility. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO and accelerated depreciation and amortization expenses associated with the previous decision to early retire the TMI nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business. |
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(h) | Primarily represents severance and reorganization costs related to a cost management program. |
| |
(i) | For Pepco, reflects an increase related to asbestos identified at its Buzzard Point property. |
| |
(j) | Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy. |
| |
(k) | Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition. |
| |
(l) | Represents the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing. |
| |
(m) | Represents the gain on the settlement of a long-term gas supply agreement at Generation. |
| |
(n) | Represents in 2016 the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon’s like-kind exchange tax position, and in 2017, adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position. |
| |
(o) | Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities. |
| |
(p) | Reflects in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition. In 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the TCJA (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA and changes in forecasted apportionment. |
| |
(q) | Reflects benefits related to the favorable settlement of certain income tax positions related to PHI's unregulated business interests. |
| |
(r) | Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT funds at CENG. |
Significant 2018 Transactions and Recent Developments
Regulatory Implications of the Tax CutsRegulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.
(b)In 2020, reflects an impairment at ComEd in the second quarter of 2020 related to the acquisition of transmission assets and Jobs Act (TCJA)an impairment of the New England asset group in the third quarter of 2020. In 2019, primarily reflects the impairment of equity method investments in certain distributed energy companies. The impact of such impairment net of noncontrolling interest is $0.02.
The Utility Registrants have made filings(c)In 2020, primarily reflects one-time charges and accelerated depreciation and amortization associated with their respective State regulatorsGeneration's decisions in the third quarter of 2020 to begin passing backearly retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024. In 2019, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility and certain fossil sites and the loss on the sale of Oyster Creek to customersHoltec, partially offset by net realized gains related to Oyster Creek's NDT fund investments, a net benefit associated with remeasurements of the ongoing annual tax savingsTMI ARO, and a gain on the sale of certain wind assets.
(d)Primarily represents reorganization and severance costs related to cost management programs.
(e)Reflects an adjustment to Generation's nuclear ARO for Non-Regulatory Agreement Units resulting from the TCJA. The amounts being proposedannual update.
(f)Represents direct costs related to be passed backCOVID-19 consisting primarily of costs to customers reflectacquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the annual benefithealth of loweremployees.
(g)Reflects the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered into on July 17, 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.
(h)Reflects costs related to the acquisition of EDF's interest in CENG.
(i)Reflects costs related to a multi-year ERP system implementation.
(j)Primarily reflects the adjustment to deferred income tax ratestaxes due to changes in forecasted apportionment.
(k)Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items. In 2020, primarily related to unrealized gains and losses on NDT fund investments for CENG units. In 2019, primarily related to the impact of unrealized gains on NDT fund investments and the settlement of a portion of deferred income tax regulatory liabilities established upon enactmentimpact of the TCJA. TheGeneration's annual nuclear ARO update for CENG units, partially offset by the impairment of certain equity investments in distributed energy companies.
Significant 2020 Transactions and Developments
Planned Separation
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants have identified over $675 million in ongoing annual savingsand Generation, creating two publicly traded companies with the resources necessary to be returnedbest serve customers and sustain long-term investment and operating excellence. The separation gives each company the financial and strategic independence to customers related to TCJA from their distribution utility operations.focus on its specific customer needs, while executing its core business strategy. See Note 426 — Regulatory MattersSubsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Impacts of February 2021 Weather Events and Texas-based Generating Assets Outages
Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced periodic outages as a result of historically severe cold weather conditions. In addition, those weather conditions drove increased demand for service, limited the availability of natural gas to fuel power plants, and dramatically increased wholesale power and gas prices.
Exelon and Generation estimate the impact to their Net income for the first quarter of 2021 arising from these market and weather conditions to be approximately $560 million to $710 million. The estimated impact includes favorable results in certain regions within Generation’s wholesale gas business. The ultimate impact to Exelon’s and Generation’s consolidated financial statements may be affected by a number of factors, including final settlement data, the impacts of customer and counterparty credit losses, any state sponsored solutions to address the financial challenges caused by the event, and litigation and contract disputes which may result. Exelon expects to offset between $410 million and $490 million of this impact primarily at Generation through a combination of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings.
See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Agreement for Sale of Generation’s Solar Business
On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation’s solar business, including 360 megawatts of generation in operation or under construction across more than 600 sites across the United States, for a purchase price of $810 million. Completion of the transaction is expected to occur in the first half of 2021. Generation will retain certain solar assets not included in this agreement, primarily Antelope Valley. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Early Retirement of Generation Facilities
In August 2020, Generation announced that it intends to retire the Byron Generating Station in September 2021, Dresden Generating Station in November 2021, and Mystic Units 8 and 9 at the expiration of the cost of service commitment in May 2024. As a result, in the third quarter of 2020, Exelon and Generation recognized a $500 million impairment of its New England asset group and one-time non-cash charges for Byron, Dresden, and Mystic related to materials and supplies inventory reserve adjustments, employee-related costs, and construction work-in-progress impairments, among other items. In addition, there will be ongoing annual financial impacts stemming from shortening the expected economic useful lives of these facilities, primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel. Such ongoing charges are excluded from Adjusted (non-GAAP) Operating Earnings.
The following table summarizes the incremental expense recorded for the year ended December 31, 2020 and the estimated amounts of incremental expense expected to be incurred through the retirement dates.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Actual | | Projected(a) |
| Income statement expense (pre-tax) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| Depreciation and amortization | | | | | | | | | |
Accelerated depreciation(b) | $ | 921 | | | $ | 2,070 | | | $ | 110 | | | $ | 120 | | | $ | 50 | |
| Accelerated nuclear fuel amortization | 60 | | | 170 | | | — | | | — | | | — | |
| Operating and maintenance | | | | | | | | | |
| One-time charges | 277 | | | 30 | | | 10 | | | — | | | 20 | |
Other charges(c) | 35 | | | 10 | | | 10 | | | 10 | | | 5 | |
| | | | | | | | | |
Contractual offset(d) | (364) | | | (475) | | | — | | | — | | | — | |
| Total | $ | 929 | | | $ | 1,805 | | | $ | 130 | | | $ | 130 | | | $ | 75 | |
| | | | | | | | | |
_________
(a)Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.
(b)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(c)Reflects primarily the net impacts associated with the remeasurement of the ARO for Dresden. See Note 10 – Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
(d)Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of the ARO for Byron and Dresden. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activities result in a regulatory liability at ComEd. Recognition of a regulatory asset for nuclear decommissioning-related activities at ComEd is not permissible. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 10 – Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
Deferred Prosecution Agreement
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into ComEd’s lobbying activities in the State of Illinois. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the United States Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date. The payments will not be recovered in rates or charged to customers, and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. See Note 19 — Commitments and Contingencies for additional information.
Utility Rates andDistribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position.
statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2018.2020. See Note 43 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
Completed Utility Distribution Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement (Decrease) Increase | | Approved Revenue Requirement (Decrease) Increase | | Approved ROE | | Approval Date | | Rate Effective Date |
| ComEd - Illinois | | April 8, 2019 | | Electric | | $ | (6) | | | $ | (17) | | | 8.91 | % | | December 4, 2019 | | January 1, 2020 |
| ComEd - Illinois | | April 16, 2020 | | Electric | | (11) | | | (14) | | | 8.38 | % | | December 9, 2020 | | January 1, 2021 |
| BGE - Maryland | | May 15, 2020 (amended September 11, 2020) | | Electric | | 137 | | | 81 | | | 9.50 | % | | December 16, 2020 | | January 1, 2021 |
| | Natural Gas | | 91 | | | 21 | | | 9.65 | % | | |
| DPL - Maryland | | December 5, 2019 (amended April 23, 2020) | | Electric | | 17 | | | 12 | | | 9.60 | % | | July 14, 2020 | | July 16, 2020 |
| DPL - Delaware | | February 21, 2020 (amended October 9, 2020) | | Natural Gas | | 7 | | | 2 | | | 9.60 | % | | January 6, 2021 | | September 21, 2020 |
|
| | | | | | | | | | | | | |
| Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase (Decrease) | | Approved Revenue Requirement Increase (Decrease) | | Approved ROE | Approval Date | Rate Effective Date |
| ComEd - Illinois (Electric) | April 16, 2018 | $ | (23 | ) | (a) | $ | (24 | ) | (a) | 8.69 | % | December 4, 2018 | January 1, 2019 |
| PECO - Pennsylvania (Electric) | March 29, 2018 | $ | 82 |
| (a) | $ | 25 |
| (a) | N/A | December 20, 2018 | January 1, 2019 |
| BGE - Maryland (Natural Gas) | June 8, 2018 (amended August 24, 2018 and October 12, 2018) | $ | 61 |
| | $ | 43 |
| | 9.8 | % | January 4, 2019 | January 4, 2019 |
| Pepco - Maryland (Electric) | January 2, 2018 (amended February 5, 2018) | $ | 3 |
| (a) | $ | (15 | ) | (a) | 9.5 | % | May 31, 2018 | June 1, 2018 |
| Pepco - District of Columbia (Electric) | December 19, 2017 (amended February 9, 2018) | $ | 66 |
| | $ | (24 | ) | (a) | 9.525 | % | August 9, 2018 | August 13, 2018 |
| DPL - Maryland (Electric) | July 14, 2017 (amended November 16, 2017) | $ | 19 |
| | $ | 13 |
| | 9.5 | % | February 9, 2018 | February 9, 2018 |
| DPL - Delaware (Electric) | August 17, 2017 (amended February 9, 2018) | $ | 12 |
| (a) | $ | (7 | ) | (a) | 9.7 | % | August 21, 2018 | March 17, 2018 |
| DPL - Delaware (Natural Gas) | August 17, 2017 (amended February 9, 2018) | $ | 4 |
| (a) | $ | (4 | ) | (a) | 9.7 | % | November 8, 2018 | March 17, 2018 |
__________
| |
(a) | Includes the annual ongoing TCJA tax savings further discussed above. |
Pending Distribution Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing |
| PECO - Pennsylvania | | September 30, 2020 | | Natural Gas | | $ | 69 | | | 10.95 | % | | Second quarter of 2021 |
| Pepco - District of Columbia | | May 30, 2019 (amended June 1, 2020) | | Electric | | 136 | | | 9.7 | % | | Second quarter of 2021 |
| Pepco - Maryland | | October 26, 2020 | | Electric | | 110 | | | 10.2 | % | | Second quarter of 2021 |
| DPL - Delaware | | March 6, 2020 (amended February 2, 2021) | | Electric | | 23 | | | 10.3 | % | | Third quarter of 2021 |
| ACE - New Jersey | | December 9, 2020 | | Electric | | 67 | | | 10.3 | % | | Fourth quarter of 2021 |
|
| | | | | | | | |
| Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase | | Requested ROE | Expected Approval Timing |
| ACE - New Jersey (Electric) | August 21, 2018 (amended November 19, 2018) | $ | 122 |
| (a) | 10.1 | % | Third quarter of 2019 |
| Pepco - Maryland (Electric) | January 15, 2019 | $ | 30 |
| | 10.3 | % | Third quarter of 2019 |
__________
| |
(a) | Includes the annual ongoing TCJA tax savings further discussed above. |
Transmission Formula RateRates
The following total increases/(decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2018the Utility Registrants' 2020 annual electric transmission formula rate updates.
|
| | | | | | | | | | | | | | |
| Registrant | Initial Revenue Requirement (Decrease) Increase(b) | Annual Reconciliation Increase/(Decrease) | Total Revenue Requirement (Decrease) Increase) | | Allowed Return on Rate Base(d) | Allowed ROE(e) |
ComEd(a) | $ | (44 | ) | $ | 18 |
| $ | (26 | ) | | 8.32 | % | 11.50 | % |
BGE(a) | 10 |
| 4 |
| 26 |
| (c) | 7.61 | % | 10.50 | % |
| Pepco | 6 |
| 2 |
| 8 |
| | 7.82 | % | 10.50 | % |
| DPL | 14 |
| 13 |
| 27 |
| | 7.29 | % | 10.50 | % |
ACE(a) | 4 |
| (4 | ) | — |
| | 8.02 | % | 10.50 | % |
__________
| |
(a) | The time period for any challenges to the annual transmission formula rate update flings expired with no challenges submitted. |
| |
(b) | The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. See Note 4 See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(c) | BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission service to specifically designated load by BGE. |
| |
(d) | Represents the weighted average debt and equity return on transmission rate bases. |
| |
(e) | As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO. |
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a revenue decrease of $6 million. The revenue decrease of $6 million included
an approximately $20 million reduction as a result of the tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.
Illinois ZEC Procurement
Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the required ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue, with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. During the year ended December 31, 2018, Generation recognized revenue of $373 million, of which $150 million related to ZECs generated from June 1, 2017 through December 31, 2017.
Early Plant Retirements
On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle and permanently ceased generation operations in September 2018. Because of the decision to early retire Oyster Creek in 2018, Exelon and Generation recognized certain one-time charges in the first quarter of 2018 related to a materials and supplies inventory reserve adjustment, employee-related costs and construction work-in-progress impairments, among other items.
On July 31, 2018, Generation entered into an agreement with Holtec International and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the sale and decommissioning of Oyster Creek. See Note 5 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant | | Initial Revenue Requirement Increase/(Decrease) | | Annual Reconciliation Decrease | | Total Revenue Requirement Increase/(Decrease) | | Allowed Return on Rate Base | | Allowed ROE |
| ComEd | | $ | 18 | | | $ | (4) | | | $ | 14 | | | 8.17 | % | | 11.50 | % |
| PECO | | 5 | | | (28) | | | (23) | | | 7.47 | % | | 10.35 | % |
| BGE | | 16 | | | (3) | | | 4 | | | 7.26 | % | | 10.50 | % |
| Pepco | | 2 | | | (46) | | | (44) | | | 7.81 | % | | 10.50 | % |
| DPL | | (4) | | | (40) | | | (44) | | | 7.20 | % | | 10.50 | % |
| ACE | | 5 | | | (25) | | | (20) | | | 7.40 | % | | 10.50 | % |
Sales of Customer Accounts Receivable
On May 30, 2017,April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by Generation, announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. The plant is currently committedentered into an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to operate through May 2019. As a resultsell certain customer accounts receivables. Generation received approximately $500 million of the early nuclear plant retirement decisions at Oyster Creek and TMI, Exelon and Generation will also recognize annual incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associatedcash in accordance with the changes in decommissioning timing and cost assumptions were also recorded. The following table summarizes the actual incremental non-cash expense item incurred in 2018 and the estimated amountinitial sale of incremental non-cash expense items expected to be incurred in 2019 due to the early retirement decisions.
|
| | | | | | | | |
| | | Actual | | Projected(a) |
| Income statement expense (pre-tax) | | 2018 | | 2019 |
Depreciation and Amortization(b) | | | | |
Accelerated depreciation(c) | | $ | 539 |
| | $ | 230 |
|
| Accelerated nuclear fuel amortization | | 57 |
| | 5 |
|
Operating and maintenance(d) | | 32 |
| | 5 |
|
| Total | | $ | 628 |
| | $ | 240 |
|
_________
| |
(a) | Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc. |
| |
(b) | Reflects incremental accelerated depreciation and amortization for TMI and Oyster Creek for the year ended December 31, 2018. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018. |
| |
(c) | Reflects incremental accelerated depreciation of plant assets, including any ARC. |
| |
(d) | Primarily includes materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments. |
In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision making authority to retire Salem.
On May 23, 2018, New Jersey enacted legislation that established a ZEC program, similar to that in Illinois and New York, that will provide compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. The NJBPU must complete its processes for determining eligibility for,
and participation in, the ZEC program by April 18, 2019. On December 19, 2018, PSEG submitted its application for Salem. Assuming the successful implementation of the New Jersey ZEC program and the selection of Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to mitigate the heightened risk of earlier retirement for Salem.approximately $1.2 billion receivables. See Note 46 — Regulatory Matters and Note 8 - Early Plant RetirementsAccounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
Generation’s Dresden, Byron,
Exelon’s Strategy and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.Outlook
On March 29, 2018, based on ISO-NE capacity auction results forFebruary 21, 2021, Exelon’s Board of Directors approved a plan to separate the 2021 - 2022 planning year in which Mystic Unit 9 did not clear,Utility Registrants and Generation, notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets absent regulatory reforms on June 1, 2022, at the end of the current capacity commitment for Mystic Units 7 and 8. As a result of these developments, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group during the first quarter of 2018 and no impairment charge was required.
The ISO-NE announced that it would take a three-step approach to fuel security.
First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel security for the 2022 - 2024 planning years. FERC denied the waiver request on procedural grounds on July 2, 2018 and ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns.
Second, in accordance with FERC's July 2, 2018 order, on August 31, 2018, ISO-NE made a filing with FERC proposing short-term tariff changes to permit it to retain a resource for fuel security reliability reasons, which FERC accepted on December 3, 2018.
Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot recover future operating costs including the cost of procuring fuel. In its July 2, 2018 order, FERC ordered ISO-NE to make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. In January 2019, ISO-NE indicated that it intends to seek an extension of the deadline for this filing to November 15, 2019.
On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service agreement reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associatedcreating two publicly traded companies with the Everett Marine Terminal. On January 4, 2019, Generation notified ISO–NE that it will participate inresources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each company the Forward Capacity Market auction for the 2022 – 2023 capacity commitment period. In addition,financial and strategic independence to focus on January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the December 20, 2018 order. The request for rehearing does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022–2023 capacity commitment period. Further developments such as the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in future impairments of the New England asset group, which could be material.its specific customer needs, while executing its core business strategy. See Note 726 — Impairment of Long-Lived Assets and Intangibles and Note 8 - Early Plant RetirementsSubsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Pension Plan Merger
Effective January 1, 2019, Exelon is mergingIn 2021, the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans is not changing the benefits offered to the plan participants and, thus, has no impactbusinesses remain focused on Exelon's pension obligation. However, beginning in 2019, actuarial
losses and gains related to the CBPP and ECRP will be amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan, which will lower Exelon’s 2019 pre-tax pension cost by approximately $90 million.
Winter Storm-Related Costs
During March 2018 there were powerful nor'easter storms that brought a mix of heavy snow, ice and high sustained winds and gusts to the region that interrupted electric service delivery to customers in PECO's, BGE's, Pepco's, DPL's and ACE's service territories. Restoration efforts included significant costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies, which resulted in incremental operating and maintenance expense and incremental capital expenditures in the first quarter of 2018 for PECO, BGE, PHI, Pepco, DPL and ACE. In addition, PHI, Pepco, DPL and ACE recorded regulatory assets for amounts that are probable of recovery through customer rates. The impacts recorded by the Registrants for the twelve months ended December 31, 2018 are presented below:
|
| | | | | | | | | | |
| | | | (in millions) |
| | Customer Outages | | Incremental Operating & Maintenance | | Incremental Capital Expenditures |
| Exelon | 1,727,000 |
| | $ | 88 |
| (b) | $ | 85 |
|
| PECO | 750,000 |
| | 53 |
| | 34 |
|
| BGE | 425,000 |
| | 31 |
| | 16 |
|
PHI(a) | 552,000 |
| | 4 |
| (b) | 35 |
|
| Pepco | 182,000 |
| | 2 |
| (b) | 4 |
|
| DPL | 138,000 |
| | 2 |
| (b) | 4 |
|
| ACE | 232,000 |
| | — |
| (b) | 27 |
|
________
| |
(a) | PHI reflects the consolidated customer outages, incremental operating & maintenance and incremental capital expenditures of Pepco, DPL and ACE. |
| |
(b) | Excludes amounts that were deferred and recognized as regulatory assets at Exelon, PHI, Pepco, DPL and ACE of $27 million, $27 million, $5 million, $1 million and $21 million, respectively. |
Westinghouse Electric Company LLC Bankruptcy
On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. On January 4, 2018, Westinghouse announced its agreement to be purchased by an affiliate of Brookfield Business Partners, LLC (Brookfield) for approximately $4.6 billion. On March 28, 2018, the Bankruptcy Court entered an Order confirming the Debtor's Second Amended Joint Plan of Reorganization which provides for the transaction with Brookfield. The transaction closed on August 1, 2018. Exelon had contracts with Westinghouse primarily related to Generation's purchase of nuclear fuel, as well as a variety of services and equipment purchases associated with the operation and maintenance of nuclear generating stations. In conjunction with the confirmation hearing, Exelon had filed a reservation of rights regarding reorganizing Westinghouse's assumption of all Exelon contracts. Exelon reached an agreement with Brookfield, and all Exelon contracts were assumed by Brookfield on the closing date.
Exelon’s Strategy and Outlook for 2019 and Beyond
Exelon’s value proposition and competitive advantage come from its scope and its core strengths ofmaintaining industry leading operational excellence, meeting or exceeding their financial commitments, ensuring timely recovery on investments to enable customer benefits, supporting enactment of clean energy policies, and financial discipline. Exelon leverages its integrated business modelcontinued commitment to create value. Exelon’s regulated and competitive businesses feature a mix of attributes that, when combined, offer shareholders and customers a unique value proposition:
The Utility Registrants provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.
Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and in long-term, contracted assets and to reduce debt.
Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.corporate responsibility.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest
reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean, and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and generationmatch supply to load matching to reduce earnings volatility.customers. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. Exelon’s Board of Directors approved a dividend policy providing a raise of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS for additional information regarding market and financial factors.
Continually optimizing the cost structure is a key component of Exelon’s financial strategy. In August 2015, Exelon announced a cost management program focused on cost savings of approximately $400 million at BSC and Generation, which was fully realized in 2018. Approximately 75% of the savings were related to Generation, with the remaining amount related to the Utility Registrants. In November 2017, Exelon announced a commitment for an additional $250 million of cost savings, primarily at Generation, to be achieved by 2020. In November 2018, Exelon announced the elimination of an approximately additional $200 million of annual ongoing costs, through initiatives primarily at Generation and BSC, by 2021. Approximately $150 million is expected to be related to Generation, with the remaining amount related to the Utility Registrants. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity.
Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses. The PHI merger enhances Exelon’s regulated growth to provide stable cash flows, earnings accretion, and dividend support. Additionally, the Utility Registrants anticipate investing approximately $29$27 billion over the next fivefour years in electric and natural gas infrastructure improvements and modernization projects, including smart grid technology, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $16$15 billion by the end of 2023.2024. The Utility Registrants invest in rate base where beneficial to customers and the community by
increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.
See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meter and Smart Grid Investments and infrastructure development and enhancement programs.
Competitive Energy Businesses. Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generationmatch supply to load matchingcustomers as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development.
Liquidity Considerations
Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.6 billion, $5.3 billion, $1.0 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion. See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities below and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
For additional information regarding the Registrants' liquidity for the year ended December 31, 2018, see Liquidity and Capital Resources discussion below.
Project Financing
Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project finance has credit facilities of $0.2 billion as of December 31, 2018. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.
Other Key Business Drivers and Management Strategies
Utility Rates and Rate Proceedings
The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results
of operations, cash flows, and financial positions. See Note 43 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings.
Power Markets
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly
over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
FERC Inquiry on Resiliency
On August 23, 2017, the DOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by base-load generation, such as nuclear plants. On September 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On January 8, 2018, FERC issued an order terminating the rulemaking docket that it initiated to address the proposed rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, FERC initiated a new proceeding to consider resiliency challenges to the bulk power system and evaluate whether additional FERC action to address resiliency would be appropriate. FERC directed each RTO and ISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. Thereafter, interested parties submitted reply comments on May 9, 2018, and a few parties submitted further replies. Exelon has been and will continue to be an active participant in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs
PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new gas-fired resources.
On January 9, 2017, EPSA filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. A similar complaint also against PJM was filed at FERC on May 31, 2018. These complaints generally allege that the relevant MOPR should be expanded to also apply to existing resources including those receiving ZEC compensation under the New York CES and Illinois ZES programs. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS programs that have generally not been subject to a MOPR. However, if successful, for Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation (Quad Cities, Ginna, Fitzpatrick and Nine Mile Point), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in future capacity auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. The same risk would also exist for the Salem facility if Salem is selected as an eligible facility under the New Jersey ZEC program.
Separately, PJM submitted two proposed alternative capacity market reforms in April 2018 for FERC’s consideration. PJM argued that either alternative will resolve any conflict between state policy support for certain resources and the need to ensure reasonable prices for non-supported resources. The first alternative was to implement a twice-run capacity clearing mechanism (known as the repricing proposal) and, if not acceptable to FERC, a second
alternative that would expand the existing MOPR to both new and existing generating resources, subject to certain exemptions (known as MOPREx).
In June 2018, FERC issued an order rejecting both of PJM’s proposed alternatives, finding both to be unjust and unreasonable. In the same order, FERC also addressed one of the MOPR complaints involving PJM and concluded based on that complaint and PJM’s filing that PJM’s existing tariff allows resources receiving out-of-market support to affect capacity prices in a manner that will cause unjust and unreasonable and unduly discriminatory rates in PJM regardless of the intent motivating the support. FERC suggested that modifying two elements of PJM’s existing tariff could produce a just and reasonable replacement and asked for initial comments on its proposal by August 28, 2018, later extended to October 2, 2018. First, FERC found that an expansion of the current MOPR mechanism to cover all existing generating resources, regardless of resource type, including those receiving either ZEC or REC compensation, could protect the capacity markets from unwanted price suppression. Second, FERC preliminarily found that a modified version of PJM’s existing Fixed Resource Requirement (FRR) option could enable state subsidized resources and a corresponding amount of load to be removed from the capacity market, thereby alleviating their price suppressive effects on capacity clearing prices. Under this alternative, state supported generating resources would potentially be compensated through mechanisms other than through PJM’s existing market mechanism. FERC established March 21, 2016 as the refund effective date and also allowed PJM to delay its next capacity auction from May 2019 to August 2019 to allow parties time to develop and file proposals in the FERC proceeding, FERC time to determine the appropriate solution and PJM time to implement FERC's solution. On October 2, 2018, Exelon, along with several ratepayer advocates, environmental organizations and other nuclear generators, submitted shared principles supporting a workable new FRR mechanism (as suggested by FERC) and detailing how such a mechanism should be implemented. Exelon also submitted individual comments covering matters not addressed in the shared principles. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. It is too early to predict the final outcome of each of these proceedings or their potential financial impact, if any, on Exelon or Generation.
Section 232 Uranium PetitionAir Quality
Mercury and Air Toxics Standards (MATS). In 2011, the EPA signed a final rule, known as MATS, to reduce emissions of hazardous air pollutants from power plants. MATS requires coal-fired power plants to achieve high removal rates of mercury, acid gases, and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. In 2016, in response to a Supreme Court decision requiring the EPA to consider costs in determining whether it was appropriate and necessary to regulate power plant emissions of hazardous air pollutants, the EPA issued a supplemental finding that, after considering costs, it remained appropriate and necessary. On January 16, 2018, two Canadian-owned uraniumMay 22, 2020, the EPA reversed course, publishing a final rule revoking the "appropriate and necessary" finding underpinning MATS. A coal mining companies with operationscompany filed a lawsuit in the U.S. jointly submittedCourt of Appeals for the D.C. Circuit seeking vacatur of MATS based on the EPA’s May 22, 2020 finding; on September 11, 2020, the U.S. Court of Appeals for the D.C. Circuit granted a petitionmotion by Exelon and two other
entities to intervene in that lawsuit to defend MATS, and on September 28, 2020, the U.S. Court of Appeals for the D.C. Circuit issued an Executive Order holding this portion of the MATS litigation in abeyance. On July 21, 2020, Exelon and two other entities filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit challenging the EPA’s May 22, 2020 rescission of the appropriate and necessary finding underpinning MATS. This portion of the case is also being held in abeyance in response to the U.S. DepartmentDOJ’s motion filed February 12, 2021. On January 20, 2021, President Biden issued an Executive Order directing the EPA to reconsider its May 22, 2020 recission by August 2021; the EPA will likely re-affirm the finding that it is appropriate and necessary to regulate power plant emissions of Commerce (DOC) seeking reliefhazardous air pollutants. As a result, this litigation is likely to be rendered moot, and MATS will likely remain in place in the interim.
Water Quality
Under the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated, and permits must be renewed periodically. Certain of Exelon's facilities discharge stormwater, industrial wastewater, and/or cooling water into waterways and are therefore subject to these regulations and operate under NPDES permits.
Clean Water Act Section 232316(b) is implemented through the NDPES program and requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. Generation’s power generation facilities with cooling water intake systems are subject to the EPA’s Section 316(b) regulations finalized in 2014; the regulation’s requirements have been or will be addressed through renewal of these facilities’ NPDES permits. Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, Generation cannot estimate the effect that compliance with the EPA’s 2014 rule will have on the operation of its generating facilities and its financial statements. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility’s economic viability could be called into question. However, the final rule does not mandate cooling towers and allows state permitting directors to require alternative, less costly technologies and/or operational measures, based on a site-specific assessment of the Trade Expansionfeasibility, costs, and benefits of available options.
On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers and allows Salem to continue to operate utilizing the existing cooling water system with certain required system modifications. However, the permit is being challenged by an environmental organization, and if successful, could result in additional costs for Clean Water Act compliance. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of 1962 (as amended) from importsthis facility.
Under Clean Water Act Section 404 and state laws and regulations, the Registrants may be required to obtain permits for projects involving dredge or fill activities in Waters of uranium products, allegingthe United States.
Where Registrants’ facilities are required to secure a federal license or permit for activities that these imports threaten national security (the Petition). The Trade Expansionmay result in a discharge to covered waters, they may be required to obtain a state water quality certification under Clean Water Act section 401.
Generation is also subject to the jurisdiction of 1962 (the Act) was promulgatedthe Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage.
Solid and Hazardous Waste and Environmental Remediation
CERCLA provides for response and removal actions coordinated by Congress to protect essential national security industries whose survival isthe EPA in the event of threatened by imports. As such, the Actreleases of hazardous substances and authorizes the SecretaryEPA either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of Commerce (the Secretary) to conduct investigations to evaluatehazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the effectscleanup costs of importshazardous waste at sites, many of any itemwhich are listed by the EPA on the national securityNational Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight. Most states have also enacted statutes that contain provisions substantially similar to CERCLA. Such statutes apply in many states where the Registrants currently own or
operate, or previously owned or operated, facilities, including Delaware, Illinois, Maryland, New Jersey, and Pennsylvania and the District of Columbia. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.
The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with these Federal and state environmental laws. Under these laws, the Registrants may be liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. The Registrants and their subsidiaries are, or could become in the future, parties to proceedings initiated by the EPA, state agencies, and/or other responsible parties under CERCLA and RCRA or similar state laws with respect to a number of sites or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party.
ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover environmental remediation costs of the U.S.MGP sites through a provision within customer rates. BGE, ACE, Pepco, and DPL do not have material contingent liabilities relating to MGP sites. The Petition alleges thatamount to be expended in 2021 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is estimated to be approximately $35 million which consists primarily of $30 million at ComEd.
As of December 31, 2020, the loss of a viable U.S. uranium mining industry wouldRegistrants have aestablished appropriate contingent liabilities for environmental remediation requirements. In addition, the Registrants may be required to make significant detrimental impact on the national, energy,additional expenditures not presently determinable for other environmental remediation costs.
See Note 3 — Regulatory Matters and economic securityNote 19 — Commitments and Contingencies of the U.S.Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ environmental matters, remediation efforts, and related impacts to the Registrants’ Consolidated Financial Statements.
Information about our Executive Officers as of February 24, 2021
Exelon
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Crane, Christopher M. | | 62 | | | Chief Executive Officer, Exelon; | | 2012 - Present |
| | | | | | |
| | | | | | |
| | | | President, Exelon | | 2008 - Present |
| | | | | | |
| | | | | | |
| Cornew, Kenneth W. | | 55 | | | Senior Executive Vice President and Chief Commercial Officer, Exelon; | | 2013 - Present |
| | | | President and CEO, Generation | | 2013 - Present |
| | | | | | |
| | | | | | |
| Butler, Calvin G. | | 51 | | | Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities | | 2019 - Present |
| | | | Chief Executive Officer, BGE | | 2014 - 2019 |
| | | | | | |
| | | | | | |
| | | | | | |
| Dominguez, Joseph | | 58 | | | Chief Executive Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2015 - 2018 |
| | | | | | |
| Glockner, David | | 60 | | | Executive Vice President, Compliance and Audit, Exelon | | 2020 - Present |
| | | | Chief Compliance Officer, Citadel LLC | | 2017 - 2020 |
| | | | Regional Director, U.S. Securities and Exchange Commission | | 2013 - 2017 |
| | | | | | |
| Hanson, Bryan C. | | 55 | | | Executive Vice President and Chief Generation Officer, Generation | | 2020 - Present |
| | | | President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Generation | | 2015 - 2020 |
| | | | | | |
| Innocenzo, Michael A. | | 55 | | | President and Chief Executive Officer, PECO | | 2018 - Present |
| | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 |
| | | | | | |
| Khouzami, Carim V. | | 45 | | | Chief Executive Officer, BGE | | 2019 - Present |
| | | | Senior Vice President, Chief Operating Officer, Exelon Utilities | | 2018 - 2019 |
| | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2016 - 2018 |
| | | | Senior Vice President, Chief Integration Officer, Exelon | | 2014 - 2016 |
| | | | | | |
| Velazquez, David M. | | 61 | | | President and Chief Executive Officer, PHI | | 2016 - Present |
| | | | President and Chief Executive Officer, Pepco, DPL, and ACE | | 2009 - Present |
| | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 |
| | | | | | |
| Von Hoene Jr., William A. | | 67 | | | Senior Executive Vice President and Chief Strategy Officer, Exelon | | 2012 - Present |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| | | | | | |
| Nigro, Joseph | | 56 | | | Senior Executive Vice President and Chief Financial Officer, Exelon | | 2018 - Present |
| | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2013 - 2018 |
| | | | | | |
| Souza, Fabian E. | | 50 | | | Senior Vice President and Corporate Controller, Exelon | | 2018 - Present |
| | | | Senior Vice President and Deputy Controller, Exelon | | 2017 - 2018 |
| | | | Vice President, Controller and Chief Accounting Officer, The AES Corporation | | 2015 - 2017 |
Generation
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Crane, Christopher M. | | 62 | | | Principle Executive Officer, Generation | | 2020 - Present |
| | | | Chief Executive Officer, Exelon; | | 2012 - Present |
| | | | President, Exelon | | 2008 - Present |
| | | | | | |
| Cornew, Kenneth W. | | 55 | | | Senior Executive Vice President and Chief Commercial Officer, Exelon; | | 2013 - Present |
| | | | President and Chief Executive Officer, Generation | | 2013 - Present |
| | | | | | |
| | | | | | |
| Swahl, William | | 51 | | | Senior Vice President, Generation; Chief Operating Officer, Exelon Power | | 2021 - Present |
| | | | Vice President, Generation; Vice President, Mid-Atlantic Operations, Exelon Power | | 2014 - 2020 |
| | | | | | |
| Hanson, Bryan C. | | 55 | | | Executive Vice President and Chief Generation Officer, Generation | | 2020 - Present |
| | | | President and Chief Nuclear Officer, Exelon Nuclear, Senior Vice President, Generation | | 2015 - 2020 |
| | | | | | |
| McHugh, James | | 49 | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2018 - Present |
| | | | Senior Vice President, Portfolio Management & Strategy, Constellation | | 2016 - 2018 |
| | | | Vice President, Portfolio Management, Constellation | | 2012 - 2016 |
| | | | | | |
| Rhoades, David | | 54 | | | Senior Vice President, Generation; President and Chief Nuclear Officer, Exelon Nuclear | | 2020 - Present |
| | | | Chief Operating Officer, Fleet Operations, Exelon Nuclear | | 2015 - 2020 |
| | | | | | |
| Wright, Bryan P. | | 54 | | | Senior Vice President and Chief Financial Officer, Generation | | 2013 - Present |
| | | | | | |
| | | | | | |
| | | | | | |
| Bauer, Matthew N. | | 44 | | | Vice President and Controller, Generation | | 2016 - Present |
| | | | Vice President and Controller, BGE | | 2014 - 2016 |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
ComEd
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Dominguez, Joseph | | 58 | | | Chief Executive Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2015 - 2018 |
| | | | | | |
| Donnelly, Terence R. | | 60 | | | President and Chief Operating Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President and Chief Operating Officer, ComEd | | 2012 - 2018 |
| | | | | | |
| Jones, Jeanne M. | | 41 | | | Senior Vice President, Chief Financial Officer and Treasurer, ComEd | | 2018 - Present |
| | | | Vice President, Finance, Exelon Nuclear | | 2014 - 2018 |
| | | | | | |
| Park, Jane | | 48 | | | Senior Vice President, Customer Operations, ComEd | | 2018 - Present |
| | | | | | |
| | | | Vice President, Regulatory Policy & Strategy, ComEd | | 2016 - 2018 |
| | | | Director, Business Strategy & Technology, ComEd | | 2014 - 2016 |
| | | | | | |
| Gomez, Veronica | | 51 | | | Senior Vice President, Regulatory and Energy Policy and General Counsel, ComEd | | 2017 - Present |
| | | | Vice President and Deputy General Counsel, Litigation, Exelon | | 2012 - 2017 |
| | | | | | |
| Washington, Melissa | | 51 | | | Senior Vice President, Governmental and External Affairs, ComEd | | 2019 - Present |
| | | | | | |
| | | | Vice President, Governmental and External Affairs, ComEd | | 2019 -2019 |
| | | | Vice President, External Affairs and Large Customer Services, ComEd | | 2016 - 2019 |
| | | | Vice President, Corporate Affairs, Exelon Business Services Company | | 2014 - 2016 |
| | | | | | |
| Perez, David | | 51 | | | Senior Vice President, Distribution Operations, ComEd | | 2019 - Present |
| | | | Vice President, Transmission and Substation, ComEd | | 2016 - 2019 |
| | | | Vice President, Regional Operations, ComEd | | 2010 - 2016 |
| | | | | | |
| | | | | | |
PECO
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Innocenzo, Michael A. | | 55 | | | President and Chief Executive Officer, PECO | | 2018 - Present |
| | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 |
| | | | | | |
| McDonald, John | | 63 | | | Senior Vice President and Chief Operations Officer, PECO | | 2018 - Present |
| | | | Vice President, Integration, PHI | | 2016 - 2018 |
| | | | Vice President, Technical Services | | 2006 - 2016 |
| Stefani, Robert J. | | 47 | | | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2018 - Present |
| | | | Vice President, Corporate Development, Exelon | | 2015 - 2018 |
| | | | | | |
| Murphy, Elizabeth A. | | 61 | | | Senior Vice President, Governmental and External Affairs, PECO | | 2016 - Present |
| | | | Vice President, Governmental and External Affairs, PECO | | 2012 - 2016 |
| | | | | | |
| | | | | | |
| Webster Jr., Richard G. | | 59 | | | Vice President, Regulatory Policy and Strategy, PECO | | 2012 - Present |
| | | | | | |
| | | | | | |
| Williamson, Olufunmilayo | | 42 | | | Senior Vice President, Customer Operations, PECO | | 2020 - Present |
| | | | Senior Vice President, Chief Commercial Risk Officer, Exelon | | 2017 - 2020 |
| | | | Vice President, Commercial Risk Management, Exelon | | 2015 - 2017 |
| | | | | | |
| Gay, Anthony | | 55 | | | Vice President and General Counsel, PECO | | 2019 - Present |
| | | | | | |
| | | | Vice President, Governmental and External Affairs, PECO | | 2016 - 2019 |
| | | | Associate General Counsel, Exelon | | 2010 - 2016 |
| | | | | | |
BGE
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Khouzami, Carim V. | | 45 | | | Chief Executive Officer, BGE | | 2019 - Present |
| | | | Senior Vice President, Chief Operating Officer, Exelon Utilities | | 2018 - 2019 |
| | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2016 - 2018 |
| | | | Senior Vice President, Chief Integration Officer, Exelon | | 2014 - 2016 |
| | | | | | |
| Woerner, Stephen J. | | 53 | | | President, BGE | | 2014 - Present |
| | | | Chief Operating Officer, BGE | | 2012 - Present |
| | | | | | |
| | | | | | |
| Vahos, David M. | | 48 | | | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present |
| | | | Vice President, Chief Financial Officer and Treasurer, BGE | | 2014 - 2016 |
| | | | | | |
| | | | | | |
| Núñez, Alexander G. | | 49 | | | Senior Vice President, Regulatory Affairs and Strategy, BGE | | 2020 - Present |
| | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - 2020 |
| | | | Vice President, Governmental and External Affairs, BGE | | 2013 - 2016 |
| | | | | | |
| Case, Mark D. | | 59 | | | Vice President, Strategy and Regulatory Affairs, BGE | | 2012 - Present |
| | | | | | |
| | | | | | |
| Oddoye, Rodney | | 44 | | | Senior Vice President, Governmental and External Affairs, BGE | | 2020 - Present |
| | | | Vice President, Customer Operations, BGE | | 2018 - 2020 |
| | | | Director, Northeast Regional Electric Operations, BGE | | 2016 - 2018 |
| | | | Director, Financial Operations, BGE | | 2015 - 2016 |
| | | | | | |
| Olivier, Tamla | | 48 | | | Senior Vice President, Customer Operations, BGE | | 2020 - Present |
| | | | Senior Vice President, Constellation NewEnergy, Inc. | | 2016 - 2020 |
| | | | VP, Human Resources, Exelon Business Services Company | | 2012 - 2016 |
| | | | | | |
| Corse, John | | 60 | | | Vice President and General Counsel, BGE | | 2018 - Present |
| | | | Associate General Counsel, Exelon | | 2012 - 2018 |
PHI, Pepco, DPL, and ACE
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Velazquez, David M. | | 61 | | | President and Chief Executive Officer, PHI | | 2016 - Present |
| | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 |
| | | | President and Chief Executive Officer, Pepco, DPL, and ACE | | 2009 - Present |
| | | | | | |
| Anthony, J. Tyler | | 56 | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - Present |
| | | | Senior Vice President, Distribution Operations, ComEd | | 2010 - 2016 |
| | | | | | |
| Barnett, Phillip S. | | 57 | | | Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL, and ACE | | 2018 - Present |
| | | | Senior Vice President and Chief Financial Officer, PECO | | 2007 - 2018 |
| | | | Treasurer, PECO | | 2012 - 2018 |
| | | | | | |
| Lavinson, Melissa | | 51 | | | Senior Vice President, Governmental & External Affairs, PHI, Pepco, DPL, and ACE | | 2018 - Present |
| | | | Vice President, Federal Affairs and Policy and Chief Sustainability Officer, PG&E Corporation | | 2015 - 2018 |
| | | | | | |
| Stark, Wendy E. | | 48 | | | Senior Vice President, Legal and Regulatory Strategy and General Counsel, PHI, Pepco, DPL, and ACE | | 2019 - Present |
| | | | Vice President and General Counsel, PHI, Pepco, DPL, and ACE | | 2016 - 2018 |
| | | | Deputy General Counsel, Pepco Holdings, Inc. | | 2012 - 2016 |
| | | | | | |
| McGowan, Kevin M. | | 59 | | | Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL, and ACE | | 2016 - Present |
| | | | Vice President, Regulatory Affairs, Pepco Holdings, Inc. | | 2012 - 2016 |
| | | | | | |
| Dickens, Derrick | | 56 | | | Senior Vice President, Customer Operations, PHI | | 2020 - Present |
| | | | Vice President, Technical Services, BGE | | 2016 - 2020 |
| | | | Director, Advanced Meter Infrastructure, PECO | | 2012 - 2016 |
| | | | | | |
| Humphrey, Marissa | | 41 | | Vice President, Regulatory Policy and Strategy, PHI, DPL, and ACE | | 2021 - Present |
| | | | Vice President Finance, Exelon Utilities | | 2019 - 2020 |
| | | | Vice President, Finance, PHI | | 2016 - 2019 |
| | | | | | |
Each of the Registrants operates in a complex market and regulatory environment that involves significant risks, many of which are beyond that Registrant’s direct control. Such risks, which could negatively affect one or more of the Registrants’ consolidated financial statements, fall primarily under the categories below:
Market and Financial Factors primarily include:
•the price of fuels, in particular the price of natural gas, which affects power prices,
•the generation resources in the markets in which the Registrants operate,
•the demand for electricity, reliability of service, and affordability in the markets where the Registrants conduct their business,
•the ability of the countryRegistrants to sustain an independent nuclear fuel cycle.
On July 18, 2018,operate their respective generating and transmission and distribution assets, their ability to access capital markets, and the Secretary announced that the DOC has initiated an investigation in responseimpacts on their results of operations due to the petition. The Secretary has 270 daysglobal outbreak (pandemic) of the 2019 novel coronavirus (COVID-19),
•the impacts of on-going competition, and
•emerging technologies and business models, including those related to prepareclimate change mitigation and submittransition to a reportlow carbon economy.
Regulatory, Legislative, and Legal Factors primarily include changes to, President Trump, who then has 90 days to act onand compliance with, the Secretary's recommendations. Exelonlaws and Generation cannot currently predict regulations that govern:
•the outcomedesign of this investigation. The relief sought bypower markets,
•ZEC programs,
•utility regulatory business models,
•environmental and climate policy, and
•tax policy.
Operational Factors primarily include:
•changes in the petitioners would require U.S. nuclear reactors to purchaseglobal climate could produce extreme weather events, which could put the Registrant’s facilities at least 25%risk, and such changes could also affect the levels and patterns of their uranium needs from domestic mines over demand for energy and related services,
•the next 10 years, although the DOC will make an independent determination regarding an appropriate remedy should it find that imports impair national security. It is reasonably possible that if this petition is successful the resulting increase in nuclear fuel costs in future periods could have a material, unfavorable impact on Exelon’ssafe, secure, and Generation’s financial statements.
Potential DOE Order Pursuant to Defense Production Act and Federal Power Act
The DOE is considering an Order directing ISOs, for 24 months, to purchase electric energy or generation capacity from a designated listeffective operation of coal and nuclear generation facilities. Based on a draft memorandum, the Order would be pursuant to DOE's authorities under the Defense Production Act and Federal Power Act, and would forestall any further actions towards retiring, decommissioning, or deactivating coal andGeneration’s nuclear facilities duringand the termability to effectively manage the associated decommissioning obligations,
•the ability of the Order. The Order would emphasizeRegistrants to maintain the importancereliability, resiliency, and safety of grid resiliency, in addition to grid reliability, noting that fuel security and diversity are critical components of resiliency. The DOE recognizes that the underlying economic and regulatory issues are complex and will take time resolve. The Order's 24-month duration would enable DOE to conduct additional analyses to gain a detailed understanding of location-specific vulnerabilities in U.S.their energy delivery systems, while preserving certainwhich could affect the operating costs of the Registrants and the opinions of their customers and regulators, and
•physical and cyber security risks for the Registrants as the owner-operators of generation, facilities.transmission, and distribution facilities and as participants in commodities trading.
Risks Related to the Planned Separation primarily include:
•the timing and conditions associated with required regulatory approvals, which may affect the costs to achieve the separation and its timing,
•challenges to achieving the benefits of separation, including maintaining investment grade credit ratings, and
•the risk that the separation could be treated as a taxable transaction to both Exelon has been and will continueits shareholders.
There may be further risks and uncertainties that are not presently known or that are not currently believed by the Registrants to be an activematerial that could negatively affect its consolidated financial statements in the future.
Market and Financial Factors
participantGeneration is exposed to price volatility associated with both the wholesale and retail power markets and the procurement of nuclear and fossil fuel (Exelon and Generation).
Generation is exposed to commodity price risk for the unhedged portion of its electricity generation supply portfolio. Generation’s earnings and cash flows are therefore exposed to variability of spot and forward market prices in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.markets in which it operates.
Price of Fuels. The spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the market during that hour. Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit.
Demand and Supply. The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable economic conditions, milder than normal weather, and the growth partially offset byof energy efficiency initiatives isand demand response programs could each depress demand. In addition, in some markets, the supply of electricity could often exceed demand during some hours of the day, resulting in relatively flat load growth in electricityloss of revenue for the Utility Registrants. ComEd, BGE, Pepco, DPLbase-load generating plants such as Generation's nuclear plants. Conversely, new demand sources such as electrification of transportation could increase demand and ACE are projecting load volumes to increase (decrease) by (0.2)%, (0.1)%, 0.3%, (0.3)% and (1.5)%, respectively, in 2019 compared to 2018. PECO is projecting load volumes to be flat in 2019 compared to 2018.change demand patterns.
Retail Competition
Competition. Generation’s retail operations compete for customers in a competitive environment, which affectaffects the margins that Generation can earn and the volumes that it is able to serve. ForwardIn periods of sustained low natural gas and power prices are expected to remainand low and thus we expectmarket volatility, retail competitors to stay aggressive in their pursuit ofcan aggressively pursue market share because the barriers to entry can be low and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.
Strategic Policy AlignmentThe impact of sustained low market prices or depressed demand and over-supply could be emphasized given Generation’s concentration of base-load electric generating capacity within primarily two geographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect Generation’s ability to fund regulated utility growth for the benefit of customers, reduce debt and provide attractive shareholder returns. In addition, such conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Generation's financial statements primarily through accelerated depreciation and amortization expenses and one-time charges. See Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
As partCost of Fuel. Generation depends on nuclear fuel and fossil fuels to operate most of its strategicgenerating facilities. The supply markets for nuclear fuel, natural gas, and oil are subject to price fluctuations, availability restrictions, and counterparty default.
Market Designs. The wholesale markets vary from region to region with distinct rules, practices, and procedures. Changes in these market rules, problems with rule implementation, or failure of any of these markets could adversely affect Generation’s business. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect on market stability.
The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry (All Registrants).
Some of these technologies include, but are not limited to, further development or applications of technologies related to shale gas production, renewable energy technologies, energy efficiency, distributed generation, and energy storage devices. Such developments could affect the price of energy, levels of customer-owned generation, customer expectations, and current business planning process,models and make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy. Each of these factors could affect the Registrants’ consolidated financial statements through, among other things, reduced operating revenues, increased operating and maintenance expenses, increased capital expenditures, and potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.
Market performance and other factors could decrease the value of NDT funds and employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants).
Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of the investments held within Generation’s NDTs and Exelon’s employee benefit plan trusts. The Registrants have significant obligations in these areas and Exelon routinely reviewsand Generation hold substantial assets in these trusts to meet those obligations. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below the Registrants’ projected return rates. A decline in the market value of the NDT fund investments could increase Generation’s funding requirements to
decommission its nuclear plants. A decline in the market value of the pension and OPEB plan assets would increase the funding requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the costs and funding requirements of the obligations related to the pension and OPEB plans. See Note 10 — Asset Retirement Obligations and Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants could be negatively affected by unstable capital and credit markets and increased volatility in commodity markets (All Registrants).
The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs. Disruptions in the capital and credit markets in the United States or abroad could negatively affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives, or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, Generation’s ability to hedge effectively its generation portfolio, changes to Generation’s hedging strategy in order to reduce collateral posting requirements, or a reduction in dividend payments or other discretionary uses of cash. In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2020, approximately 23%, 19%, and 18% of the Registrants’ available credit facilities were with European, Canadian, and Asian banks, respectively. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities.
The strength and depth of competition in energy markets depend heavily on active participation by multiple trading parties, which could be negatively affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that could affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power, including the requirement of long-term contracts.
If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties, it would be required to provide significant amounts of collateral under its agreements with counterparties and could experience higher borrowing costs (All Registrants).
Generation’s business is subject to credit quality standards that could require market participants to post collateral for their obligations. If Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating) or otherwise fail to satisfy the credit standards of trading counterparties, it would be required under its hedging policy, dividend policy,arrangements to provide collateral in the form of letters of credit or cash, which could have a material adverse effect upon its liquidity. The amount of collateral required to be provided by Generation at any point in time depends on a variety of factors, including (1) the notional amount of the applicable hedge, (2) the nature of counterparty and related agreements, and (3) changes in power or other commodity prices. In addition, if Generation were downgraded, it could experience higher borrowing costs as a result of the downgrade. Changes in ratings methodologies by the credit rating agencies could also have a negative impact on the ratings of Generation.
Generation has project-specific financing arrangements and must meet the requirements of various agreements relating to those financings. Failure to meet those arrangements could give rise to a project-specific financing default which, if not cured or waived, could result in the specific project being required to repay the associated
debt or other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have broad remedies, including rights to foreclose against the project assets and related collateral or to force the Exelon subsidiaries in the project-specific financings to enter into bankruptcy proceedings. The impact of bankruptcy could result in the impairment of certain project assets.
The Utility Registrants' operating agreements with PJM and PECO's, BGE's, and DPL's natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO, BGE, and DPL, with respect to their natural gas supply contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. If the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade. In addition, changes in ratings methodologies by the agencies could also have an adverse negative impact on the ratings of the Utility Registrants.
The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters — Market Conditions and Security Ratings for additional information regarding the potential impacts of credit downgrades on the Registrants’ cash flows.
Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities (Exelon and Generation).
Generation’s asset-based power position as well as its power marketing, fuel procurement, and other commodity trading activities expose Generation to risks of commodity price movements. Generation buys and sells energy and other products and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolio. Generation is exposed to volatility in financial results for unhedged positions as well as the risk of ineffective hedges. Generation attempts to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations could be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its commodity trading activities and risk management decisions could have on its consolidated financial statements.
Financial performance and load requirements could be negatively affected if Generation is unable to effectively manage its power portfolio (Exelon and Generation).
A significant portion of Generation’s power portfolio is used to provide power under procurement contracts with the Utility Registrants and other customers. To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale power markets. To the extent its power portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale power markets. Generation’s financial results could be negatively affected if it is unable to cost-effectively meet the load requirements of its customers, manage its power portfolio or effectively address the changes in the wholesale power markets.
The impacts of significant economic downturns or increases in customer rates, could lead to decreased volumes delivered and increased expense for uncollectible customer balances (All Registrants).
The impacts of significant economic downturns on the Utility Registrants' customers, such as less demand for products and services provided by commercial and industrial customers, and the related regulatory limitations on residential service terminations, could result in an increase in the number of uncollectible customer balances. Further, increases in customer rates, including those related to increases in purchased power and natural gas prices, could result in declines in customer usage and lower revenues for the Utility Registrants that do not have decoupling mechanisms.
Generation's customer-facing energy delivery activities face similar economic downturn risks, such as lower volumes sold and increased expense for uncollectible customer balances.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information of the Registrants’ credit risk.
The Registrants' results could be negatively affected by the impacts of COVID-19 (All Registrants).
COVID-19 is an evolving situation that could lead to extended disruption of economic activity in the Registrants’ respective markets. COVID-19 could negatively affect the Registrants’ ability to operate their respective generating and transmission and distribution assets, their ability to access capital markets, and their results of operations. The Registrants cannot predict the extent of the impacts of COVID-19, which will depend on future developments and which are highly uncertain. See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Executive Overview for additional information.
The Registrants could be negatively affected by the impacts of weather (All Registrants).
Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting revenues at PECO, DPL Delaware, and ACE. Due to revenue decoupling, BGE, Pepco, and DPL Maryland recognize revenues at MDPSC and DCPSC-approved levels per customer, regardless of what actual distribution volumes are for a billing period and are not affected by actual weather with the exception of major storms. ComEd’s customer rates are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenue.
Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems, and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customer demand. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant.
Generation’s operations are also affected by weather, which affects demand for electricity as well as operating conditions. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation could require greater resources to meet its contractual commitments. Extreme weather conditions or storms could affect the availability of generation and its transmission, limiting Generation’s ability to source or send power to where it is sold. In addition, drought-like conditions limiting water usage could impact Generation’s ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could cause Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when markets are weak.
Climate change projections suggest increases to summer temperature and humidity trends, as well as more erratic precipitation and storm patterns over the long-term in the areas where Registrants have generation, transmission, and distribution assets. The frequency in which weather conditions emerge outside the current expected climate norms could contribute to weather-related impacts discussed above.
Long-lived assets, goodwill, and other assets could become impaired (All Registrants).
Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. In addition, Exelon, ComEd, and PHI have material goodwill balances.
The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered.
ComEd and PHI perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Regulatory actions or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco’s, DPL’s, and ACE’s business, and the fair value of debt, could potentially result in future impairments of Exelon’s, ComEd's, and PHI’s goodwill.
An impairment would require the Registrants to reduce the carrying value of the long-lived asset or goodwill to fair value through a non-cash charge to expense by the amount of the impairment. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, Note 8 — Property, Plant, and Equipment, Note 12 — Asset Impairments and Note 13 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset impairments and goodwill impairments.
The Registrants could incur substantial costs in the event of non-performance by third-parties under indemnification agreements, or when the Registrants have guaranteed their performance. Generation is exposed to other credit risks in the power markets that are beyond its control (All Registrants).
The Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations. Each of the Utility Registrants has transferred its former generation business to a third party and in each case the transferee has agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO, and BGE transferred their generating assets to Generation, Generation assumed certain of ComEd’s, PECO’s, and BGE's rights and obligations with respect to their former generation businesses. Further, ComEd, PECO, and BGE have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO, or BGE for certain obligations related to their respective former generation businesses that have been assumed by Generation as part of the restructuring. If the third-party, Generation, or the transferee of Pepco's, DPL's, or ACE’s generation facilities experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims. In addition, the Utility Registrants have residual liability under certain laws in connection with their former generation facilities.
The Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets and they could incur substantial costs to fulfill their obligations under these indemnities.
The Registrants have issued guarantees of the performance of third parties, which obligate the Registrants to perform in the event that the third parties do not perform. In the event of non-performance by those third parties, the Registrants could incur substantial cost to fulfill their obligations under these guarantees.
In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money or are obligated to purchase energy or fuel from Generation, will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent amounts, if any, were already paid to the counterparties. In the spot markets, Generation is
exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, Generation’s retail sales subject it to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer.
Regulatory, Legislative, and Legal Factors
Federal or state legislative or regulatory actions could negatively affect the scope and functioning of the wholesale markets (Exelon and Generation).
Approximately 70% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the area encompassed by PJM. Generation’s future results of operations are impacted by (1) FERC’s and PJM's support for policies that favor the preservation of competitive wholesale power markets and recognize the value of zero-carbon electricity and resiliency and for states' energy objectives and policies (2) the absence of material changes to market structures that would limit or otherwise negatively affect Exelon or Generation. Generation could also be affected by state laws, regulations, or initiatives to subsidize existing or new generation.
FERC’s requirements for market-based rate authority could pose a risk that Generation may no longer satisfy FERC’s tests for market-based rates.
The Registrants’ are highly regulated and could be negatively affected by regulatory and legislative actions (All Registrants).
Substantially all aspects of the businesses of the Registrants are subject to comprehensive Federal or state regulation and legislation.
Generation’s consolidated financial statements are significantly affected by its sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated rates and Federal and state regulatory and legislative developments related to emissions, climate change, capacity market mitigation, energy price information, resilience, fuel diversity, and RPS. Legislative and regulatory efforts in Illinois, New York, and New Jersey to preserve the environmental attributes and reliability benefits of zero-emission nuclear-powered generating facilities through ZEC programs are or could be subject to legal and regulatory challenges and, if overturned, could result in the early retirement of certain of Generation’s nuclear plants. See Note 3 — Regulatory Matters and Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs for the retail purchase and distribution of power and natural gas to their customers.
Fundamental changes in regulations or other adverse legislative actions affecting the Registrants’ businesses would require changes in their business planning models and operations. The Registrants cannot predict when or whether legislative and regulatory proposals could become law or what their effect will be on the Registrants.
Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy, and subject to appeal, which lead to uncertainty as to the ultimate result and which could introduce time delays in effectuating rate changes (Exelon and the Utility Registrants).
The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of
energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, credit losses, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs. In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives, or franchise agreements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants to recover their costs or earn an adequate return. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.
NRC actions could negatively affect the operations and profitability of Generation’s nuclear generating fleet (Exelon and Generation).
Regulatory risk. A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital spending plans, strengthexpenditures or could result in increased operating or decommissioning costs. Events at nuclear plants owned by others, as well as those owned by Generation, could cause the NRC to initiate such actions.
Spent nuclear fuel storage. The approval of a national repository for the storage of SNF and the timing of such a facility opening, will significantly affect the costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse Generation for these costs.
Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect Generation’s ability to fully decommission its nuclear units. Generation cannot predict what, if any, fee may be established in the future for SNF disposal. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the SNF obligation.
The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of PJM’s RTEP and NERC compliance requirements (All Registrants).
The Registrants as users, owners, and operators of the bulk power transmission system, including Generation and the Utility Registrants, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. PECO, BGE, and DPL, as operators of natural gas distribution systems, are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DPSC, and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Registrants were found not to be in compliance with the Federal and state mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants).
The businesses that the Registrants operate are subject to extensive environmental regulation and legislation by local, state, and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions, hazardous and solid waste, and activities affecting surface waters, groundwater, and aquatic and other species. Violations of these requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages, or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property
contaminated by hazardous substances they generated or released. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future. See ITEM 1. BUSINESS — Environmental Regulation for additional information.
The Registrants could be negatively affected by challenges to tax positions taken, tax law changes, and the inherent difficulty in quantifying potential tax effects of business decisions. (All Registrants).
The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Significant Accounting Policies and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants could be negatively affected by federal and state RPS and/or energy conservation legislation, along with energy conservation by customers (All Registrants).
Changes to current state legislation or the development of Federal legislation that requires the use of clean, renewable, and alternate fuel sources could significantly impact Generation and the Utility Registrants, especially if timely cost recovery is not allowed for Utility Registrants. The impact could include increased costs and increased rates for customers.
Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, could increase capital expenditures and could significantly impact the Utility Registrants consolidated financial statements if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to a decline in the revenues of the Registrants. See ITEM 1. BUSINESS — Environmental Regulation — Renewable and Clean Energy Standards for additional information.
Generation’s affiliation with the Utility Registrants, together with the presence of a substantial percentage of Generation’s physical asset base within the Utility Registrants' service territories, could increase Generation’s cost of doing business to the extent future complaints or challenges regarding the Utility Registrants' retail rates result in settlements or legislative or regulatory requirements funded in part by Generation (Exelon and Generation).
Generation has significant generating resources within the service areas of the Utility Registrants and makes significant sales to each of them. Those facts tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators, and advocacy groups are aware of Generation’s affiliation with the Utility Registrants and its sales to each of them. In periods of rising utility rates, particularly when driven by increased costs of energy production and supply, those officials and advocacy groups could question or challenge costs and transactions incurred by the Utility Registrants with Generation, irrespective of any previous regulatory processes or approvals underlying those transactions. These challenges could increase the time, complexity, and cost of the associated regulatory proceedings, and the occurrence of such challenges could subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. In addition, government officials and legislators could seek ways to force Generation to contribute to efforts to mitigate potential or actual rate increases, through measures such as generation-based taxes.
The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences (All Registrants).
The Registrants could be the subject of public criticism. Adverse publicity of this nature could render public service commissions and other regulatory and legislative authorities less likely to view energy companies such as Exelon and its subsidiaries in a favorable light, and could cause Exelon and its subsidiaries to be susceptible
to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements (e.g. disallowances of costs, lower ROEs).
Legal proceedings could result in a negative outcome, which the Registrants cannot predict (All Registrants).
The Registrants are involved in legal proceedings, claims, and litigation arising out of their business operations. The material ones are summarized in Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue, or restrict existing business activities.
Exelon and ComEd have received requests for information related to an SEC investigation into their lobbying activities. The outcome of the investigations could have a material adverse effect on their reputation and consolidated financial statements (Exelon and ComEd).
On October 22, 2019, the SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the state of Illinois. Exelon and ComEd have cooperated fully, including by providing all information requested by the SEC, and intend to continue to cooperate fully and expeditiously with the SEC. The outcome of the SEC’s investigation cannot be predicted and could subject Exelon and ComEd to civil penalties, sanctions, or other remedial measures. Any of the foregoing, as well as the appearance of non-compliance with anti-corruption and anti-bribery laws, could have an adverse impact on Exelon’s and ComEd’s reputations or relationships with regulatory and legislative authorities, customers, and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
If ComEd violates its Deferred Prosecution Agreement announced on July 17, 2020, it could have an adverse effect on the reputation and consolidated financial statements of Exelon and ComEd (Exelon and ComEd).
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including, but not limited to, the following: (i) payment to the United States Treasury of $200 million; (ii) continued full cooperation with the government’s investigation; and (iii) ComEd’s adoption and maintenance of remedial measures involving compliance and reporting undertakings as specified in the DPA. If ComEd is found to have breached the terms of the DPA, the USAO may elect to prosecute, or bring a civil action against, ComEd for conduct alleged in the DPA or known to the government, which could result in fines or penalties and could have an adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
Generation’s financial performance could be negatively affected by risks arising from its ownership and operation of hydroelectric facilities (Exelon and Generation).
FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands or connected to the interstate electric grid. Generation cannot predict whether it will receive all the regulatory approvals for the renewed licenses of its balance sheet and credit metrics, and sufficiencyhydroelectric facilities. If FERC does not issue new operating licenses for Generation’s hydroelectric facilities or a station cannot be operated through the end of its liquidity position,operating license, Generation’s results of operations could be adversely affected by performingincreased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation could also lose
revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, could require a substantial increase in capital expenditures, could result in increased operating costs or could render the project uneconomic. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by Generation.
Operational Factors
The Registrants are subject to risks associated with climate change (All Registrants).
The Registrants periodically perform analyses to better understand how climate change could affect their facilities and operations. The Registrants primarily operate in the Midwest and East Coast of the United States, areas that historically have been prone to various stress teststypes of severe weather events, such that the Registrants have well-developed response and recovery programs based on these historical events. However, the Registrants’ physical facilities could be placed at greater risk of damage should changes in the global climate impact temperature and weather patterns, resulting in more intense, frequent and extreme weather events, unprecedented levels of precipitation, sea level rise, increased surface water temperatures, and/or other effects. In addition, changes to the climate may impact levels and patterns of demand for energy and related services, which could affect Registrants’ operations. Over time, the Registrants may need to make additional investments to protect facilities from physical climate-related risks and/or adapt to changes in operational requirements as a result of climate change.
The Registrants also periodically perform analyses of potential pathways to reduce power sector and economy-wide GHG emissions to mitigate climate change. To the extent additional GHG reduction regulation or legislation becomes effective at the Federal and/or state levels, the Registrants could incur costs to further limit the GHG emissions from their operations or otherwise comply with differing variables,applicable requirements. To the extent such additional regulation or legislation does not become effective, the potential competitive advantage offered by Registrant’s low-carbon emission profile may be reduced. See ITEM 1. BUSINESS — Climate Change Mitigation.
Generation’s financial performance could be negatively affected by matters arising from its ownership and operation of nuclear facilities (Exelon and Generation).
Nuclear capacity factors. Capacity factors for nuclear generating units, significantly affect Generation’s results of operations. Lower capacity factors could decrease Generation’s revenues and increase operating costs by requiring Generation to produce additional energy from primarily its fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to committed third-party sales, including the Utility Registrants. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations.
Nuclear refueling outages. In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refueling outages, along with their duration, could have a significant impact on Generation’s results of operations. When refueling outages last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease, and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales and higher operating and maintenance costs.
Nuclear fuel quality. The quality of nuclear fuel utilized by Generation could affect the efficiency and costs of Generation’s operations. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs, and/or increased costs due to decreased generation capabilities.
Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation must shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. Generation could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation could lose revenue and incur increased fuel and purchased power expense to meet supply commitments.
For plants operated but not wholly owned by Generation, Generation could also incur liability to the co-owners. For nuclear plants not operated and not wholly owned by Generation, from which Generation receives a portion of the plants’ output, Generation’s results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants. Additionally, poor operating
performance at nuclear plants not owned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy. In addition, closure of generating plants owned by others, or extended interruptions of generating plants, or failure of transmission lines, could affect transmission systems that could adversely affect the sale and delivery of electricity in markets served by Generation.
Nuclear major incident risk and insurance. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by Generation or owned by others, could exceed Generation’s resources, including insurance coverage. Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation’s nuclear operations. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by Generation. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned by Generation or others, could result in increased regulation and reduced public support for nuclear-fueled energy.
As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance, $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $13.8 billion limit for a single incident.
See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of nuclear insurance.
Decommissioning obligation and funding. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility.
Generation recognizes as a liability the present value of the estimated future costs to decommission its nuclear facilities. The estimated liability is based on assumptions in the approach and timing of decommissioning the nuclear facilities, estimation of decommissioning costs, and Federal and state regulatory requirements. The costs of such decommissioning may substantially exceed such liability, as facts, circumstances or our estimates may change, including changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in Federal or state regulatory requirements on the decommissioning of such facilities, other changes in our estimates or Generation’s ability to effectively execute on its planned decommissioning activities.
Generation makes contributions to certain trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to Generation. While Generation, through PECO, has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from utility customers for any of its other nuclear units if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation would be unable to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units could be negatively affected.
Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income, and the adverse impact to Exelon’s and Generation’s financial statements could be material. Any changes to the existing PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s financial statements could be material.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. If the investments held by Generation’s NDT funds are not sufficient to fund the decommissioning of Generation’s nuclear units, Generation could be required to take steps, such as commodity price movements,providing financial guarantees through letters of credit or parent
company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met.
See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants' operating costs are affected by their ability to maintain the availability and reliability of their delivery and operational systems (Exelon and the Utility Registrants).
Failures of the equipment or facilities used in the Utility Registrants' delivery systems could interrupt the electric transmission and electric and natural gas delivery, which could result in a loss of revenues and an increase in maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of AMI, smart grid, or other technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems, or if any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results could be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal and/or external tampering or manipulation of those systems will result in losses that are difficult to detect.
Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers, which could be material.
The Registrants are subject to physical security and cybersecurity risks (All Registrants).
The Registrants face physical security and cybersecurity risks. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural gas utility industry associated with protection of sensitive and confidential information, grid infrastructure, and other energy infrastructures, and such attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of advanced digital technologies increases the potentially unfavorable impacts of such attacks. A security breach of the physical assets or information systems of the Registrants, their competitors, vendors, business partners and interconnected entities in margin-related transactions,RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor, and employee data, trading or other confidential data. The risk of these system-related events and security breaches occurring continues to intensify, and while the Registrants have been, and will likely continue to be, subjected to physical and cyber-attacks, to date none has directly experienced a material breach or disruption to its network or information systems or our service operations. However, as such attacks continue to increase in sophistication and frequency, the Registrants may be unable to prevent all such attacks in the future. If a significant breach were to occur, the reputation of the Registrants could be negatively affected, customer confidence in the Registrants or others in the industry could be diminished, or the Registrants could be subject to legal claims, loss of revenues, increased costs, or operations shutdown. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result.
The Utility Registrants' deployment of smart meters throughout their service territories could increase the risk of damage from an intentional disruption of the system by third parties.
In addition, new or updated security regulations or unforeseen threat sources could require changes in hedging practices,current measures taken by the Registrants or their business operations and could adversely affect their consolidated financial statements.
The Registrants’ employees, contractors, customers, and the general public could be exposed to a risk of injury due to the nature of the energy industry (All Registrants).
Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous environments near the Registrants’ operations. As a result, employees,
contractors, customers, and the general public are at some risk for serious injury, including loss of life. These risks include nuclear accidents, dam failure, gas explosions, pole strikes, and electric contact cases.
Natural disasters, war, acts and threats of terrorism, pandemic, and other significant events could negatively impact the Registrants' results of operations, their ability to raise capital and their future growth (All Registrants).
Generation’s fleet of power plants and the Utility Registrants' distribution and transmission infrastructures could be affected by natural disasters and extreme weather events, which could result in increased costs, including supply chain costs. An extreme weather event within the Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Natural disasters and other significant events increase the risk to Generation that the NRC or other regulatory or legislative bodies could change the laws or regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning, security, and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units.
The impact that potential terrorist attacks could have on the industry and on Exelon is uncertain. The Registrants face a risk that their operations would be direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect their operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these catastrophic events could compromise the physical or cybersecurity of Exelon’s facilities, which could adversely affect Exelon’s ability to manage its business effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession, or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.
The Registrants could be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate Exelon's generating and transmission and distribution assets could be affected.
In addition, Exelon maintains a level of hypothetical credit downgrades.insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses.
Exelon'sThe Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability (All Registrants).
The Registrants’ businesses are capital intensive and require significant investments by Generation in electric generating facilities and by the Utility Registrants in transmission and distribution infrastructure projects. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Registrants’ control, and could require significant expenditures to operate efficiently. The Registrants consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources for additional information regarding the Registrants’ potential future capital expenditures.
The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by transmission congestion and failures of neighboring transmission systems (Exelon and the Utility Registrants).
Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission
capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures.
PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. However, service interruptions at other utilities may cause interruptions in the Utility Registrants’ service areas.
The Registrants consolidated financial statements could be negatively affected if they fail to attract and retain an appropriately qualified workforce (All Registrants).
Certain events, such as an employee strike, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, could arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their generation, transmission, and distribution operations.
The Registrants could make acquisitions or investments in new business initiatives and new markets, which may not be successful or achieve the intended financial results (All Registrants).
Generation could continue to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. This could include investment opportunities in renewables, development of natural gas generation, nuclear advisory or operating services for third parties, distributed generation, potential expansion of the existing wholesale gas businesses, and entry into LNG. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered during diligence performed prior to launching an initiative or entering a market. Additionally, it is possible that FERC, state public utility commissions or others could impose certain other restrictions on such transactions. All of these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment.
The Utility Registrants face risks associated with their regulatory-mandated initiatives, such as smart grids and utility of the future. These risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity, and obsolescence of technology. Such initiatives may not be successful.
The Registrants may not realize or achieve the anticipated cost savings through the cost management efforts (All Registrants).
The Registrants’ future financial performance and level of profitability is dependent, in part, on various cost reduction initiatives. The Registrants may encounter challenges in executing these cost reduction initiatives and not achieve the intended cost savings.
Risks Related to the Planned Separation (Exelon and Generation)
The planned separation is contingent upon regulatory approvals and satisfaction of other conditions and may not be completed in accordance with the expected plans or anticipated timeline, or at all, which could negatively affect Exelon’s and Generation’s consolidated financial statements.
Exelon is targeting to complete the separation in the first quarter of 2022, subject to final approval by Exelon’s Board of Directors, a Form 10 registration statement being declared effective by the SEC, regulatory approvals, and satisfaction of other conditions. The planned separation is subject to approval by the FERC, NRC and NYPSC. There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing. If the planned separation is not completed or is delayed, Exelon’s and Generation’s consolidated financial statements may be materially adversely affected, and the market price of Exelon’s common stock may be affected.
The plan to separate into two publicly traded companies will involve significant time and expense, which could disrupt or adversely affect our business.
The planned separation is complex in nature, and unanticipated developments or changes, including challenges in executing the separation, could delay or prevent the completion of the proposed separation, or cause the separation to occur on terms or conditions that are different or less favorable than expected. Additionally, Exelon’s Board of Directors, in its sole and absolute discretion, may decide not to proceed with the separation at any time prior to the distribution date. The process of completing the proposed separation has been and is expected to continue to be time-consuming and involves significant costs and expenses.
The planned separation may not achieve some or all of the anticipated benefits and each separate company following the separation may underperform relative to Exelon’s expectations.
By separating the Utility Registrants and Generation, Exelon is creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separate companies are expected to create value by having the strategic flexibility to focus on their unique customer, market and community priorities. However, the planned separation may not provide such results on the scope or scale that Exelon anticipates, and Exelon and Generation may not realize the anticipated benefits of the planned separation. Failure to do so could have a material adverse effect on the financial statements of each separate company and their respective common stock price.
Following the planned separation, the companies anticipate to maintain investment grade credit ratings. Ratings are based upon assessments of multiple factors, including a company’s credit metrics as well as industry and macroeconomic changes and trends. If a rating agency were to downgrade the rating below investment grade, the separate companies’ borrowing costs would increase and their funding sources could decrease, which could have a material adverse effect on the financial statements of the affected company.
The common stock of the separately publicly traded companies following the separation may collectively trade at a value less than the price at which Exelon’s common stock might have traded had the separation not occurred.
There could be significant liability if the planned spin-off is determined to be a taxable transaction.
Under the separation plan, Exelon shareholders will retain their current shares of Exelon stock and receive a pro-rata distribution of shares of the new company’s stock in a transaction that is expected to be tax-free to Exelon and its shareholders under Sections 355 and 368 of the IRC. Exelon will seek a private letter ruling from the IRS regarding the tax-free nature of the transaction. Exelon will also seek from its tax advisors an opinion with respect to certain U.S. federal income tax consequences of the spin-off. If the planned spin-off ultimately is determined to be taxable, the spin-off could be treated as a taxable dividend to Exelon’s shareholders for U.S. federal income tax purposes, and Exelon’s shareholders could incur significant U.S. federal income tax liabilities. In addition, Exelon would recognize a taxable gain to the extent that the fair market value of the new company’s stock exceeds its tax basis in such stock on the date of the planned separation. Exelon will enter into a Tax Matters Agreement with the new company to address how post-separation issues will be managed between the companies, as well as which company is responsible for taxes imposed as a result of the planned separation, if any.
See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information on the planned separation.
| | | | | |
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
All Registrants
None.
Generation
The following table presents Generation’s interests in net electric generating capacity by station at December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Station(a) | | Location | | No. of
Units | | Percent Owned(b) | | Primary
Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
| Midwest | | | | | | | | | | | | | |
| Braidwood | | Braidwood, IL | | 2 | | | | | Uranium | | Base-load | | 2,386 | | |
| Byron | | Byron, IL | | 2 | | | | | Uranium | | Base-load | | 2,347 | | (e) |
| LaSalle | | Seneca, IL | | 2 | | | | | Uranium | | Base-load | | 2,320 | | |
| Dresden | | Morris, IL | | 2 | | | | | Uranium | | Base-load | | 1,845 | | (e) |
| Quad Cities | | Cordova, IL | | 2 | | | 75 | | | Uranium | | Base-load | | 1,403 | | (f) |
| Clinton | | Clinton, IL | | 1 | | | | | Uranium | | Base-load | | 1,080 | | |
| Michigan Wind 2 | | Sanilac Co., MI | | 50 | | | 51 | | (g) | Wind | | Intermittent | | 46 | | (f) |
| Beebe | | Gratiot Co., MI | | 34 | | | 51 | | (g) | Wind | | Intermittent | | 42 | | (f) |
| Michigan Wind 1 | | Huron Co., MI | | 46 | | | 51 | | (g) | Wind | | Intermittent | | 35 | | (f) |
| Harvest 2 | | Huron Co., MI | | 33 | | | 51 | | (g) | Wind | | Intermittent | | 30 | | (f) |
| Harvest | | Huron Co., MI | | 32 | | | 51 | | (g) | Wind | | Intermittent | | 27 | | (f) |
| Beebe 1B | | Gratiot Co., MI | | 21 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) |
| City Solar | | Chicago, IL | | 1 | | | | | Solar | | Intermittent | | 9 | | |
| Solar Ohio | | Toledo, OH | | 2 | | | | | Solar | | Intermittent | | 4 | | (h) |
| Blue Breezes | | Faribault Co., MN | | 2 | | | | | Wind | | Intermittent | | 3 | | |
| CP Windfarm | | Faribault Co., MN | | 2 | | | 51 | | (g) | Wind | | Intermittent | | 2 | | (f) |
| Southeast Chicago | | Chicago, IL | | 8 | | | | | Gas | | Peaking | | 296 | | (i) |
| Clinton Battery Storage | | Blanchester, OH | | 1 | | | | | Energy Storage | | Peaking | | 10 | | |
| Total Midwest | | | | | | | | | | | | 11,911 | | |
| | | | | | | | | | | | | |
| Mid-Atlantic | | | | | | | | | | | | | |
| Limerick | | Sanatoga, PA | | 2 | | | | | Uranium | | Base-load | | 2,317 | | |
| Peach Bottom | | Delta, PA | | 2 | | | 50 | | | Uranium | | Base-load | | 1,324 | | (f) |
| Salem | | Lower Alloways
Creek Township, NJ | | 2 | | | 42.59 | | | Uranium | | Base-load | | 995 | | (f) |
| Calvert Cliffs | | Lusby, MD | | 2 | | | 50.01 | | (j) | Uranium | | Base-load | | 895 | | (f) |
| Conowingo | | Darlington, MD | | 11 | | | | | Hydroelectric | | Base-load | | 572 | | |
| Criterion | | Oakland, MD | | 28 | | | 51 | | (g) | Wind | | Intermittent | | 36 | | (f) |
| Fair Wind | | Garrett County, MD | | 12 | | | | | Wind | | Intermittent | | 30 | | |
| Solar MC | | Various, MD | | 44 | | | | | Solar | | Intermittent | | 44 | | (h) |
| Fourmile Ridge | | Garrett County, MD | | 16 | | | 51 | | (g) | Wind | | Intermittent | | 20 | | (f) |
| Solar New Jersey 1 | | Various, NJ | | 5 | | | | | Solar | | Intermittent | | 18 | | (h) |
| Solar New Jersey 2 | | Various, NJ | | 2 | | | | | Solar | | Intermittent | | 11 | | (h) |
| Solar Horizons | | Emmitsburg, MD | | 1 | | | 51 | | (g) | Solar | | Intermittent | | 16 | | (f) |
| Solar Maryland | | Various, MD | | 11 | | | | | Solar | | Intermittent | | 8 | | (h) |
| Solar Maryland 2 | | Various, MD | | 3 | | | | | Solar | | Intermittent | | 8 | | (h) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Station(a) | | Location | | No. of
Units | | Percent Owned(b) | | Primary
Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
| JBAB Solar | | District of Columbia | | 4 | | | | | Solar | | Intermittent | | 7 | | (h) |
| Gateway Solar | | Berlin, MD | | 1 | | | | | Solar | | Intermittent | | 7 | | (h) |
| Constellation New Energy | | Gaithersburg, MD | | 2 | | | | | Solar | | Intermittent | | 6 | | (h) |
| Solar Federal | | Trenton, NJ | | 1 | | | | | Solar | | Intermittent | | 5 | | (h) |
| Solar New Jersey 3 | | Middle Township, NJ | | 5 | | | 51 | | (g) | Solar | | Intermittent | | 2 | | (f) |
| Solar DC | | District of Columbia | | 1 | | | | | Solar | | Intermittent | | 1 | | (h) |
| Muddy Run | | Drumore, PA | | 8 | | | | | Hydroelectric | | Intermediate | | 1,070 | | |
| Eddystone 3, 4 | | Eddystone, PA | | 2 | | | | | Oil/Gas | | Peaking | | 760 | | |
| Perryman | | Aberdeen, MD | | 5 | | | | | Oil/Gas | | Peaking | | 404 | | |
| Croydon | | West Bristol, PA | | 8 | | | | | Oil | | Peaking | | 391 | | |
| Handsome Lake | | Kennerdell, PA | | 5 | | | | | Gas | | Peaking | | 268 | | |
| Richmond | | Philadelphia, PA | | 2 | | | | | Oil | | Peaking | | 98 | | |
| Philadelphia Road | | Baltimore, MD | | 4 | | | | | Oil | | Peaking | | 61 | | |
| Eddystone | | Eddystone, PA | | 4 | | | | | Oil | | Peaking | | 60 | | |
| Delaware | | Philadelphia, PA | | 4 | | | | | Oil | | Peaking | | 56 | | |
| Southwark | | Philadelphia, PA | | 4 | | | | | Oil | | Peaking | | 52 | | |
| Falls | | Morrisville, PA | | 3 | | | | | Oil | | Peaking | | 51 | | |
| Moser | | Lower Pottsgrove Twp., PA | | 3 | | | | | Oil | | Peaking | | 51 | | |
| Chester | | Chester, PA | | 3 | | | | | Oil | | Peaking | | 39 | | |
| Schuylkill | | Philadelphia, PA | | 2 | | | | | Oil | | Peaking | | 30 | | |
| Salem | | Lower Alloways
Creek Township, NJ | | 1 | | | 42.59 | | | Oil | | Peaking | | 16 | | (f) |
| Total Mid-Atlantic | | | | | | | | | | | | 9,729 | | |
| | | | | | | | | | | | | |
| ERCOT | | | | | | | | | | | | | |
| Whitetail | | Webb County, TX | | 57 | | | 51 | | (g) | Wind | | Intermittent | | 47 | | (f) |
| Sendero | | Jim Hogg and Zapata County, TX | | 39 | | | 51 | | (g) | Wind | | Intermittent | | 40 | | (f) |
| Constellation Solar Texas | | Various, TX | | 11 | | | | | Solar | | Intermittent | | 13 | | (h) |
| Colorado Bend II | | Wharton, TX | | 3 | | | | | Gas | | Intermediate | | 1,143 | | |
| Wolf Hollow II | | Granbury, TX | | 3 | | | | | Gas | | Intermediate | | 1,115 | | |
| Handley 3 | | Fort Worth, TX | | 1 | | | | | Gas | | Intermediate | | 395 | | |
| Handley 4, 5 | | Fort Worth, TX | | 2 | | | | | Gas | | Peaking | | 870 | | |
| Total ERCOT | | | | | | | | | | | | 3,623 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Station(a) | | Location | | No. of
Units | | Percent Owned(b) | | Primary
Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
| New York | | | | | | | | | | | | | |
| Nine Mile Point | | Scriba, NY | | 2 | | | 50.01 | | (j) | Uranium | | Base-load | | 838 | | (f) |
| FitzPatrick | | Scriba, NY | | 1 | | | | | Uranium | | Base-load | | 842 | | |
| Ginna | | Ontario, NY | | 1 | | | 50.01 | | (j) | Uranium | | Base-load | | 288 | | (f) |
| Solar New York | | Bethlehem, NY | | 1 | | | | | Solar | | Intermittent | | 3 | | (h) |
| Total New York | | | | | | | | | | | | 1,971 | | |
| | | | | | | | | | | | | |
| Other | | | | | | | | | | | | | |
| Antelope Valley | | Lancaster, CA | | 1 | | | | | Solar | | Intermittent | | 242 | | |
| Bluestem | | Beaver County, OK | | 60 | | | 51 | | (g)(k) | Wind | | Intermittent | | 101 | | (f) |
| Shooting Star | | Kiowa County, KS | | 65 | | | 51 | | (g) | Wind | | Intermittent | | 53 | | (f) |
| Albany Green Energy | | Albany, GA | | 1 | | | 99 | | (l) | Biomass | | Base-load | | 50 | | (f) |
| Solar Arizona | | Various, AZ | | 127 | | | | | Solar | | Intermittent | | 46 | | (h) |
| Bluegrass Ridge | | King City, MO | | 27 | | | 51 | | (g) | Wind | | Intermittent | | 29 | | (f) |
| California PV Energy 2 | | Various, CA | | 89 | | | | | Solar | | Intermittent | | 27 | | (h) |
| Conception | | Barnard, MO | | 24 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) |
| Cow Branch | | Rock Port, MO | | 24 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) |
| Solar Arizona 2 | | Various, AZ | | 56 | | | | | Solar | | Intermittent | | 34 | | (h) |
| California PV Energy | | Various, CA | | 53 | | | | | Solar | | Intermittent | | 21 | | (h) |
| Mountain Home | | Glenns Ferry, ID | | 20 | | | 51 | | (g) | Wind | | Intermittent | | 21 | | (f) |
| High Mesa | | Elmore Co., ID | | 19 | | | 51 | | (g) | Wind | | Intermittent | | 20 | | (f) |
| Echo 1 | | Echo, OR | | 21 | | | 50.49 | | (g) | Wind | | Intermittent | | 17 | | (f) |
| Sacramento PV Energy | | Sacramento, CA | | 4 | | | 51 | | (g) | Solar | | Intermittent | | 30 | | (f) |
| Cassia | | Buhl, ID | | 14 | | | 51 | | (g) | Wind | | Intermittent | | 15 | | (f) |
| Wildcat | | Lovington, NM | | 13 | | | 51 | | (g) | Wind | | Intermittent | | 14 | | (f) |
| Echo 2 | | Echo, OR | | 10 | | | 51 | | (g) | Wind | | Intermittent | | 10 | | (f) |
| Solar Georgia 2 | | Various, GA | | 8 | | | | | Solar | | Intermittent | | 10 | | (h) |
| Tuana Springs | | Hagerman, ID | | 8 | | | 51 | | (g) | Wind | | Intermittent | | 9 | | (f) |
| Solar Georgia | | Various, GA | | 10 | | | | | Solar | | Intermittent | | 8 | | (h) |
| Greensburg | | Greensburg, KS | | 10 | | | 51 | | (g) | Wind | | Intermittent | | 6 | | (f) |
| Solar Massachusetts | | Various, MA | | 10 | | | | | Solar | | Intermittent | | 7 | | (h) |
| Outback Solar | | Christmas Valley, OR | | 1 | | | | | Solar | | Intermittent | | 6 | | (h) |
| Echo 3 | | Echo, OR | | 6 | | | 50.49 | | (g) | Wind | | Intermittent | | 5 | | (f) |
| Holyoke Solar | | Various, MA | | 2 | | | | | Solar | | Intermittent | | 5 | | (h) |
| Three Mile Canyon | | Boardman, OR | | 6 | | | 51 | | (g) | Wind | | Intermittent | | 5 | | (f) |
| Loess Hills | | Rock Port, MO | | 4 | | | | | Wind | | Intermittent | | 5 | | |
| California PV Energy 3 | | Various, CA | | 31 | | | | | Solar | | Intermittent | | 8 | | (h) |
| Denver Airport Solar | | Denver, CO | | 1 | | | 51 | | (g) | Solar | | Intermittent | | 4 | | (f) |
| Solar Net Metering | | Uxbridge, MA | | 1 | | | | | Solar | | Intermittent | | 2 | | (h) |
| Solar Connecticut | | Various, CT | | 1 | | | | | Solar | | Intermittent | | 1 | | (h) |
| Mystic 8, 9 | | Charlestown, MA | | 6 | | | | | Gas | | Intermediate | | 1,413 | | (e) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Station(a) | | Location | | No. of
Units | | Percent Owned(b) | | Primary
Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
| Hillabee | | Alexander City,
AL | | 3 | | | | | Gas | | Intermediate | | 753 | | |
| Mystic 7 | | Charlestown, MA | | 1 | | | | | Oil/Gas | | Intermediate | | 512 | | (m) |
| Wyman 4 | | Yarmouth, ME | | 1 | | | 5.9 | | | Oil | | Intermediate | | 35 | | (f) |
| Grand Prairie | | Alberta, Canada | | 1 | | | | | Gas | | Peaking | | 105 | | |
| West Medway | | West Medway, MA | | 3 | | | | | Oil | | Peaking | | 124 | | |
| West Medway II | | West Medway, MA | | 2 | | | | | Oil/Gas | | Peaking | | 192 | | |
| Framingham | | Framingham, MA | | 3 | | | | | Oil | | Peaking | | 31 | | |
| | | | | | | | | | | | | |
| Mystic Jet | | Charlestown, MA | | 1 | | | | | Oil | | Peaking | | 9 | | (m) |
| Total Other | | | | | | | | | | | | 4,037 | | |
| Total | | | | | | | | | | | | 31,271 | | |
__________
(a)All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, and Salem, which are pressurized water reactors.
(b)100%, unless otherwise indicated.
(c)Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are plants with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods.
(d)For nuclear stations, capacity reflects the annual mean rating. Fossil stations and wind and solar facilities reflect a summer rating.
(e)Generation has announced it will permanently cease generation operations at Byron and Dresden nuclear facilities in 2021 and Mystic Unit 8 and 9 in 2024. See Note 7 — Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information.
(f)Net generation capacity is stated at proportionate ownership share.
(g)Reflects the prior sale of 49% of EGRP to a third party. See Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information.
(h)On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation's solar business. The transaction is expected to be completed in the first second, thirdhalf of 2021. See Note 2 — Mergers, Acquisitions, and fourth quarter 2018 dividendsDispositions of $0.3450the Combined Notes to the Consolidated Financial Statements for additional information.
(i)Generation has deactivated the site and is evaluating for potential return of service or retirement beyond 2021.
(j)Reflects Generation’s interest in CENG, a joint venture with EDF. See ITEM 1. — BUSINESS — Exelon Generation Company, LLC — Nuclear Facilities for additional information.
(k)EGRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets.
(l)Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity.
(m)Generation has plans to retire and cease plant operations in 2021.
The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies, or generating units being temporarily out of service for inspection, maintenance, refueling, repairs, or modifications required by regulatory authorities.
Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding nuclear insurance of generating facilities, see ITEM 1. BUSINESS — Exelon Generation Company, LLC. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in Generation’s consolidated financial condition or results of operations.
The Utility Registrants
The Utility Registrants' electric substations and a portion of their transmission rights are located on property that they own. A significant portion of their electric transmission and distribution facilities are located above or underneath highways, streets, other public places, or property that others own. The Utility Registrants believe that they have satisfactory rights to use those places or property in the form of permits, grants, easements, licenses, and franchise rights; however, they have not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
The Utility Registrants’ high voltage electric transmission lines owned and in service at December 31, 2020 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Voltage | | Circuit Miles | |
| (Volts) | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | |
| 765,000 | | 90 | | — | | — | | — | | — | | — | |
500,000(a) | | — | | 188 | (a) | 216 | | 109 | | 16 | (a) | — | (a) |
| 345,000 | | 2,676 | | — | | — | | — | | — | | — | |
| 230,000 | | — | | 549 | | 358 | | 770 | | 472 | | 274 | |
| 138,000 | | 2,245 | | 135 | | 55 | | 61 | | 586 | | 214 | |
| 115,000 | | — | | — | | 712 | | 25 | | — | | — | |
| 69,000 | | — | | 177 | | — | | — | | 567 | | 667 | |
___________
(a) In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 9 - Jointly Owned Electric Utility Plant - for additional information.
The Utility Registrants' electric distribution system includes the following number of circuit miles of overhead and underground lines:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Circuit Miles | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
| Overhead | | 35,379 | | 12,967 | | 9,179 | | 4,082 | | 6,007 | | 7,393 |
| Underground | | 32,349 | | 9,463 | | 17,650 | | 6,949 | | 6,360 | | 2,984 |
Gas
The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2020:
| | | | | | | | | | | | | | | | | | | | |
| PECO | | BGE | | DPL | |
| Transmission | 9 | | 152 | | 8 | (a) |
| Distribution | 6,946 | | 7,443 | | 2,142 | |
| Service piping | 6,449 | | 6,383 | | 1,461 | |
| Total | 13,404 | | 13,978 | | 3,611 | |
___________
(a) DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities.
The following table presents PECO’s, BGE’s, and DPL’s natural gas facilities:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant | | Facility | | Location | | Storage Capacity
(mmcf) | | Send-out or Peaking Capacity
(mmcf/day) |
| PECO | | LNG Facility | | West Conshohocken, PA | | 1,200 | | 160 |
| PECO | | Propane Air Plant | | Chester, PA | | 105 | | 25 |
| BGE | | LNG Facility | | Baltimore, MD | | 1,056 | | 332 |
| BGE | | Propane Air Plant | | Baltimore, MD | | 550 | | 85 |
| DPL | | LNG Facility | | Wilmington, DE | | 250 | | 25 |
PECO, BGE, and DPL also own 30, 30, and 10 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout their gas service territory, respectively.
First Mortgage and Insurance
The principal properties of ComEd, PECO, PEPCO, DPL, and ACE are subject to the lien of their respective Mortgages under which their respective First Mortgage Bonds are issued. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants maintain property insurance against loss or damage to their properties by fire or other perils, subject to certain exceptions. For their insured losses, the Utility Registrants are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of the Utility Registrants.
Exelon
Security Measures
The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes, and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.
All Registrants
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.
| | | | | |
| ITEM 4. | MINE SAFETY DISCLOSURES |
All Registrants
Not Applicable to the Registrants.
PART II
(Dollars in millions except per share each on Exelon'sdata, unless otherwise noted)
| | | | | |
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Exelon
Exelon’s common stock is listed on the Nasdaq (trading symbol: EXC). As of January 31, 2021, there were 976,337,799 shares of common stock outstanding and approximately 91,240 record holders of common stock.
Stock Performance Graph
The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, as compared with the S&P 500 Stock Index and the first quarter 2019 dividends declared was $0.3625. The dividendsS&P Utility Index, for the first, second, thirdperiod 2016 through 2020.
This performance chart assumes:
•$100 invested on December 31, 2015 in Exelon common stock, the S&P 500 Stock Index, and fourth quarter 2018the S&P Utility Index; and
•All dividends are reinvested.
| | | | | | | | | | | | | | | | | | | | |
| Value of Investment at December 31, |
| 2015 | 2016 | 2017 | 2018 | 2019 | 2020 |
| Exelon Corporation | $100 | $132.81 | $152.79 | $180.80 | $188.53 | $181.20 |
| S&P 500 | $100 | $111.96 | $136.40 | $130.42 | $171.49 | $203.04 |
| S&P Utilities | $100 | $116.29 | $130.36 | $135.72 | $171.48 | $172.31 |
Generation
As of January 31, 2021, Exelon indirectly held the entire membership interest in Generation.
ComEd
As of January 31, 2021, there were 127,021,370 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 31, 2021, in addition to Exelon, there were 286 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.
PECO
As of January 31, 2021, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon.
BGE
As of January 31, 2021, there were 1,000 outstanding shares of common stock, without par value, of BGE, all of which were indirectly held by Exelon.
PHI
As of January 31, 2021, Exelon indirectly held the entire membership interest in PHI.
Pepco
As of January 31, 2021, there were 100 outstanding shares of common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon.
DPL
As of January 31, 2021, there were 1,000 outstanding shares of common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon.
ACE
As of January 31, 2021, there were 8,546,017 outstanding shares of common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon.
All Registrants
Dividends
Under applicable Federal law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to Exelon.
ComEd has agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its
guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.
Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the DPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid on March 9, 2018, June 8, 2018, September 10, 2018 and December 10, 2018, respectively. The first quarter 2019 dividend is payable on March 8, 2019.if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.
Exelon’s Board of Directors approved an updated dividend policy providingfor 2021. The 2021 quarterly dividend will remain the same as the 2020 dividend of $0.3825 per share.
At December 31, 2020, Exelon had retained earnings of $16,735 million, including Generation’s undistributed earnings of $2,805 million, ComEd’s retained earnings of $1,456 million consisting of retained earnings appropriated for future dividends of $3,095 million, partially offset by $1,639 million of unappropriated accumulated deficits, PECO’s retained earnings of $1,519 million, BGE’s retained earnings of $1,879 million, and PHI's undistributed losses of $68 million.
The following table sets forth Exelon’s quarterly cash dividends per share paid during 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 |
| (per share) | Fourth
Quarter | | Third
Quarter | | Second
Quarter | | First
Quarter | | Fourth
Quarter | | Third
Quarter | | Second
Quarter | | First
Quarter |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Exelon | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3625 | | | $ | 0.3625 | | | $ | 0.3625 | | | $ | 0.3625 | |
The following table sets forth Generation's and PHI's quarterly distributions and ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's quarterly common dividend payments:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 |
| (in millions) | 4th
Quarter | | 3rd
Quarter | | 2nd
Quarter | | 1st
Quarter | | 4th
Quarter | | 3rd
Quarter | | 2nd
Quarter | | 1st
Quarter |
| Generation | $ | 328 | | | $ | 469 | | | $ | 469 | | | $ | 468 | | | $ | 225 | | | $ | 225 | | | $ | 224 | | | $ | 225 | |
| ComEd | 126 | | | 124 | | | 124 | | | 125 | | | 128 | | | 126 | | | 127 | | | 127 | |
| PECO | 85 | | | 85 | | | 85 | | | 85 | | | 90 | | | 88 | | | 90 | | | 90 | |
| BGE | 60 | | | 62 | | | 62 | | | 62 | | | 55 | | | 57 | | | 56 | | | 56 | |
| PHI | 102 | | | 183 | | | 134 | | | 134 | | | 97 | | | 213 | | | 88 | | | 128 | |
| Pepco | 58 | | | 73 | | | 73 | | | 28 | | | 40 | | | 101 | | | 48 | | | 24 | |
| DPL | 42 | | | 33 | | | 14 | | | 52 | | | 34 | | | 35 | | | 29 | | | 41 | |
| ACE | 3 | | | 76 | | | 12 | | | 23 | | | 24 | | | 76 | | | 12 | | | 12 | |
First Quarter 2021 Dividend
On February 21, 2021, Exelon's Board of Directors declared a regular quarterly dividend of $0.3825 per share on Exelon’s common stock for the first quarter of 2021. The dividend is payable on Monday, March 15, 2021, to shareholders of record of Exelon as of 5 p.m. Eastern time on Monday, March 8, 2021.
| | | | | |
| Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Exelon
Executive Overview
Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
Exelon has eleven reportable segments consisting of Generation’s five reportable segments (Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2020 compared to the year ended December 31, 2019, and is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. For discussion of the year ended December 31, 2019 compared to the year ended December 31, 2018, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2019 Form 10-K, which was filed with the SEC on February 11, 2020.
COVID-19. The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of COVID-19. The Registrants provide a critical service to our customers which means that it is paramount that we keep our employees who operate our businesses safe and minimize unnecessary risk of exposure to the virus. The Registrants have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities. The Registrants have implemented work from home policies where appropriate, and imposed travel limitations on their employees. In addition, the Registrants have updated existing business continuity plans in the context of this pandemic.
The Registrants continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers.
There were no changes in internal control over financial reporting in 2020 as a result of COVID-19 that materially affected, or are reasonably likely to materially affect, any of the Registrants’ internal control over financial reporting. See ITEM 9A. CONTROLS AND PROCEDURES for additional information.
Unfavorable economic conditions due to COVID-19 have impacted the demand for electricity and natural gas at Generation and the Utility Registrants, which has resulted in a decrease in operating revenues.
As a result of COVID-19, Generation temporarily suspended interruption of service for all retail residential customers for non-payment and temporarily ceased new late payment fees for all retail customers from March to May of 2020. Starting in March of 2020, the Utility Registrants also temporarily suspended customer disconnections for non-payment and temporarily ceased new late payment fees for all customers and restored service to customers upon request who were disconnected in the last twelve months. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on such measures at the Utility Registrants. At Generation, such measures resulted in an increase of 5% each yearin credit loss expense. ComEd and ACE recorded regulatory assets for the incremental credit loss expense based on existing mechanisms. BGE, PECO, Pepco, and DPL also recorded regulatory assets for substantially all the incremental credit loss expense incurred in 2020. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Generation and the Utility Registrants have also incurred direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of their employees. At Generation and PECO, such costs are recorded as Operating and maintenance expense and are excluded from Adjusted (non-GAAP) Operating Earnings. At ComEd, BGE, Pepco, DPL, and ACE, such costs are primarily recorded as regulatory assets. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The estimated impact to Generation’s and the Utility Registrants’ Net income is approximately $170 million and $75 million for the year ended December 31, 2020, respectively.
To offset the unfavorable impacts from COVID-19, the Registrants identified approximately $250 million in cost savings across Generation and the Utility Registrants in 2020. The cost savings achieved in 2020 were higher than originally anticipated.
The Registrants rely on the capital markets for publicly offered debt as well as the commercial paper markets to meet their financial commitments and short-term liquidity needs. As a result of the disruptions in the commercial paper markets in March of 2020, Generation borrowed $1.5 billion on its revolving credit facility to refinance commercial paper, which Generation repaid on April 3, 2020. Generation also entered into two short-term loan agreements in March of 2020 for an aggregate of $500 million. On April 8, 2020, Generation received approximately $500 million in cash after entering into an accounts receivable financing arrangement. On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility to be used as an additional source of short-term liquidity. In addition, the Registrants issued long-term debt of $5.3 billion and were able to successfully complete their planned long-term debt issuances in 2020. See Liquidity and Capital Resources, Note 17 — Debt and Credit Agreements, and Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants assessed long-lived assets, goodwill, and investments for recoverability and there were no material impairment charges recorded in 2020 as a result of COVID-19. See Note 12 — Asset Impairments for additional information related to other impairment assessments in the third quarter of 2020. Certain assumptions are highly sensitive to changes. Changes in significant assumptions could potentially result in future impairments, which could be material.
This is an evolving situation that could lead to extended disruption of economic activity in our markets. The Registrants will continue to monitor developments affecting their workforce, customers, and suppliers and will take additional precautions that they determine to be necessary in order to mitigate the impacts. The extent to which COVID-19 may impact the Registrants’ ability to operate their generating and transmission and distribution assets, the ability to access capital markets, and results of operations, including demand for electricity and natural gas, will depend on the spread and proliferation of COVID-19 around the world and future developments, which are highly uncertain and cannot be predicted at this time.
Financial Results of Operations
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the year ended December 31, 2020 compared to the same period covering 2018 throughin 2019. For additional information regarding the financial results for the years ended December 31, 2020 beginningand2019 see the discussions of Results of Operations by Registrant.
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | (Unfavorable) Favorable Variance |
| Exelon | $ | 1,963 | | | $ | 2,936 | | | $ | (973) | |
| Generation | 589 | | | 1,125 | | | (536) | |
| ComEd | 438 | | | 688 | | | (250) | |
| PECO | 447 | | | 528 | | | (81) | |
| BGE | 349 | | | 360 | | | (11) | |
| PHI | 495 | | | 477 | | | 18 | |
| Pepco | 266 | | | 243 | | | 23 | |
| DPL | 125 | | | 147 | | | (22) | |
| ACE | 112 | | | 99 | | | 13 | |
Other(a) | (355) | | | (242) | | | (113) | |
__________
(a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income attributable to common shareholdersdecreased by $973 million and diluted earnings per average common share decreased to $2.01 in 2020 from $3.01 in 2019 primarily due to:
•One-time charges and accelerated depreciation and amortization associated with Generation's decisions in the March 2018 dividend.third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024, partially offset by the absence of accelerated depreciation and amortization due to the early retirement of TMI in September 2019;
Hedging Strategy•Impairment of the New England asset group;
Exelon’s policy
•Payments that ComEd made under the Deferred Prosecution Agreement. See Note 19 — Commitments and Contingencies of the Combined Notes to hedge commodity riskConsolidated Financial Statements for additional information;
•Lower capacity revenue;
•Reduction in load due to COVID-19 at Generation;
•Lower realized energy prices;
•Higher nuclear outage days;
•Impact of Generation's annual update to the nuclear ARO for Non-Regulatory Agreement Units;
•Lower net unrealized and realized gains on NDT funds;
•COVID-19 direct costs;
•Lower electric distribution earnings from lower allowed ROE due to a ratable basis over three-year periodsdecrease in treasury rates, partially offset by higher rate base at ComEd;
•Higher storm costs related to the June 2020 and August 2020 storms at PECO, net of tax repairs, and related to the August 2020 storm at DPL;
•Unfavorable weather conditions at PECO, DPL Delaware, and ACE; and
•A net increase in depreciation and amortization expense due to ongoing capital expenditures at PECO, BGE, Pepco, DPL, and ACE, partially offset at Generation due to the impact of extending the operating license at Peach Bottom.
The decreases were partially offset by;
•Higher mark-to-market gains;
•Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter and were fair valued based on quoted market prices of the stocks as of December 31, 2020;
•Lower operating and maintenance expense at Generation primarily due to previous cost management programs, lower contracting costs, and lower travel costs, partially offset by lower NEIL insurance distributions;
•Lower nuclear fuel costs;
•A tax benefit related to a settlement in the first quarter of 2020, partially offset by the absence of a tax benefit related to certain research and development activities recorded in the fourth quarter of 2019 at Generation;and
•Regulatory rate increases at BGE, DPL, and ACE.
Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to reduceenhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the financialongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
The following table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2020 as compared to 2019:
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| 2020 | | 2019 |
| (All amounts in millions after tax) | | | Earnings per
Diluted Share | | | | Earnings per
Diluted Share |
| Net Income Attributable to Common Shareholders | $ | 1,963 | | | $ | 2.01 | | | $ | 2,936 | | | $ | 3.01 | |
| Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $73 and $66, respectively) | (213) | | | (0.22) | | | 197 | | | 0.20 | |
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $278 and $269, respectively)(a) | (256) | | | (0.26) | | | (299) | | | (0.31) | |
| | | | | | | |
Asset Impairments (net of taxes of $135 and $56, respectively)(b) | 396 | | | 0.41 | | | 123 | | | 0.13 | |
Plant Retirements and Divestitures (net of taxes of $244 and $9, respectively)(c) | 718 | | | 0.74 | | | 118 | | | 0.12 | |
Cost Management Program (net of taxes of $14 and $17, respectively)(d) | 45 | | | 0.05 | | | 51 | | | 0.05 | |
| Litigation Settlement Gain (net of taxes of $7) | — | | | — | | | (19) | | | (0.02) | |
Asset Retirement Obligation (net of taxes of $16 and $9, respectively)(e) | 48 | | | 0.05 | | | (84) | | | (0.09) | |
| Change in Environmental Liabilities (net of taxes of $6 and $8, respectively) | 18 | | | 0.02 | | | 20 | | | 0.02 | |
COVID-19 Direct Costs (net of taxes of $19)(f) | 50 | | | 0.05 | | | — | | | — | |
Deferred Prosecution Agreement Payments (net of taxes of $0)(g) | 200 | | | 0.20 | | | — | | | — | |
Acquisition Related Costs (net of taxes of $1)(h) | 4 | | | — | | | — | | | — | |
ERP System Implementation Costs (net of taxes of $1)(i) | 3 | | | — | | | — | | | — | |
Income Tax-Related Adjustments (entire amount represents tax expense)(j) | 71 | | | 0.07 | | | 5 | | | 0.01 | |
Noncontrolling Interests (net of taxes of $19 and $26, respectively)(k) | 103 | | | 0.11 | | | 90 | | | 0.09 | |
| Adjusted (non-GAAP) Operating Earnings | $ | 3,149 | | | $ | 3.22 | | | $ | 3,139 | | | $ | 3.22 | |
__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of market price volatility. Generationeach reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is exposedbased on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to commodity price riskNDT funds, the marginal statutory income tax rates for 2020 and 2019 ranged from 26.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT funds were 52.1% and 47.3% for the years ended December 31, 2020 and 2019, respectively.
(a)Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.
(b)In 2020, reflects an impairment at ComEd in the second quarter of 2020 related to the acquisition of transmission assets and an impairment of the New England asset group in the third quarter of 2020. In 2019, primarily reflects the impairment of equity method investments in certain distributed energy companies. The impact of such impairment net of noncontrolling interest is $0.02.
(c)In 2020, primarily reflects one-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024. In 2019, primarily reflects accelerated depreciation and amortization expenses associated with the unhedgedearly retirement of the TMI nuclear facility and certain fossil sites and the loss on the sale of Oyster Creek to Holtec, partially offset by net realized gains related to Oyster Creek's NDT fund investments, a net benefit associated with remeasurements of the TMI ARO, and a gain on the sale of certain wind assets.
(d)Primarily represents reorganization and severance costs related to cost management programs.
(e)Reflects an adjustment to Generation's nuclear ARO for Non-Regulatory Agreement Units resulting from the annual update.
(f)Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(g)Reflects the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered into on July 17, 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.
(h)Reflects costs related to the acquisition of EDF's interest in CENG.
(i)Reflects costs related to a multi-year ERP system implementation.
(j)Primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.
(k)Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items. In 2020, primarily related to unrealized gains and losses on NDT fund investments for CENG units. In 2019, primarily related to the impact of unrealized gains on NDT fund investments and the impact of the Generation's annual nuclear ARO update for CENG units, partially offset by the impairment of certain equity investments in distributed energy companies.
Significant 2020 Transactions and Developments
Planned Separation
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Impacts of February 2021 Weather Events and Texas-based Generating Assets Outages
Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced periodic outages as a result of historically severe cold weather conditions. In addition, those weather conditions drove increased demand for service, limited the availability of natural gas to fuel power plants, and dramatically increased wholesale power and gas prices.
Exelon and Generation estimate the impact to their Net income for the first quarter of 2021 arising from these market and weather conditions to be approximately $560 million to $710 million. The estimated impact includes favorable results in certain regions within Generation’s wholesale gas business. The ultimate impact to Exelon’s and Generation’s consolidated financial statements may be affected by a number of factors, including final settlement data, the impacts of customer and counterparty credit losses, any state sponsored solutions to address the financial challenges caused by the event, and litigation and contract disputes which may result. Exelon expects to offset between $410 million and $490 million of this impact primarily at Generation through a combination of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings.
See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Agreement for Sale of Generation’s Solar Business
On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts,Generation’s solar business, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties,360 megawatts of generation in operation or under construction across more than 600 sites across the United States, for a purchase price of $810 million. Completion of the transaction is expected to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2019 and 2020. However, Generation is exposed to relatively greater commodity price riskoccur in the subsequent years with respectfirst half of 2021. Generation will retain certain solar assets not included in this agreement, primarily Antelope Valley. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to whichConsolidated Financial Statements for additional information.
Early Retirement of Generation Facilities
In August 2020, Generation announced that it intends to retire the Byron Generating Station in September 2021, Dresden Generating Station in November 2021, and Mystic Units 8 and 9 at the expiration of the cost of service commitment in May 2024. As a larger portionresult, in the third quarter of 2020, Exelon and Generation recognized a $500 million impairment of its electricity portfolio is currently unhedged. AsNew England asset group and one-time non-cash charges for Byron, Dresden, and Mystic related to materials and supplies inventory reserve adjustments, employee-related costs, and construction work-in-progress impairments, among other items. In addition, there will be ongoing annual financial impacts stemming from shortening the expected economic useful lives of these facilities, primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel. Such ongoing charges are excluded from Adjusted (non-GAAP) Operating Earnings.
The following table summarizes the incremental expense recorded for the year ended December 31, 2018,2020 and the percentageestimated amounts of incremental expense expected generation hedgedto be incurred through the retirement dates.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Actual | | Projected(a) |
| Income statement expense (pre-tax) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| Depreciation and amortization | | | | | | | | | |
Accelerated depreciation(b) | $ | 921 | | | $ | 2,070 | | | $ | 110 | | | $ | 120 | | | $ | 50 | |
| Accelerated nuclear fuel amortization | 60 | | | 170 | | | — | | | — | | | — | |
| Operating and maintenance | | | | | | | | | |
| One-time charges | 277 | | | 30 | | | 10 | | | — | | | 20 | |
Other charges(c) | 35 | | | 10 | | | 10 | | | 10 | | | 5 | |
| | | | | | | | | |
Contractual offset(d) | (364) | | | (475) | | | — | | | — | | | — | |
| Total | $ | 929 | | | $ | 1,805 | | | $ | 130 | | | $ | 130 | | | $ | 75 | |
| | | | | | | | | |
_________
(a)Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.
(b)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(c)Reflects primarily the net impacts associated with the remeasurement of the ARO for Dresden. See Note 10 – Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
(d)Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of the ARO for Byron and Dresden. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activities result in a regulatory liability at ComEd. Recognition of a regulatory asset for nuclear decommissioning-related activities at ComEd is not permissible. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 10 – Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
Deferred Prosecution Agreement
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Mid-Atlantic, Midwest, New YorkNorthern District of Illinois (USAO) to resolve the USAO’s investigation into ComEd’s lobbying activities in the State of Illinois. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and ERCOT reportable segmentsoffered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the United States Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date. The payments will not be recovered in rates or charged to customers, and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. See Note 19 — Commitments and Contingencies for additional information.
Utility Distribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2020. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement (Decrease) Increase | | Approved Revenue Requirement (Decrease) Increase | | Approved ROE | | Approval Date | | Rate Effective Date |
| ComEd - Illinois | | April 8, 2019 | | Electric | | $ | (6) | | | $ | (17) | | | 8.91 | % | | December 4, 2019 | | January 1, 2020 |
| ComEd - Illinois | | April 16, 2020 | | Electric | | (11) | | | (14) | | | 8.38 | % | | December 9, 2020 | | January 1, 2021 |
| BGE - Maryland | | May 15, 2020 (amended September 11, 2020) | | Electric | | 137 | | | 81 | | | 9.50 | % | | December 16, 2020 | | January 1, 2021 |
| | Natural Gas | | 91 | | | 21 | | | 9.65 | % | | |
| DPL - Maryland | | December 5, 2019 (amended April 23, 2020) | | Electric | | 17 | | | 12 | | | 9.60 | % | | July 14, 2020 | | July 16, 2020 |
| DPL - Delaware | | February 21, 2020 (amended October 9, 2020) | | Natural Gas | | 7 | | | 2 | | | 9.60 | % | | January 6, 2021 | | September 21, 2020 |
Pending Distribution Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing |
| PECO - Pennsylvania | | September 30, 2020 | | Natural Gas | | $ | 69 | | | 10.95 | % | | Second quarter of 2021 |
| Pepco - District of Columbia | | May 30, 2019 (amended June 1, 2020) | | Electric | | 136 | | | 9.7 | % | | Second quarter of 2021 |
| Pepco - Maryland | | October 26, 2020 | | Electric | | 110 | | | 10.2 | % | | Second quarter of 2021 |
| DPL - Delaware | | March 6, 2020 (amended February 2, 2021) | | Electric | | 23 | | | 10.3 | % | | Third quarter of 2021 |
| ACE - New Jersey | | December 9, 2020 | | Electric | | 67 | | | 10.3 | % | | Fourth quarter of 2021 |
Transmission Formula Rates
The following total increases/(decreases) were included in the Utility Registrants' 2020 annual electric transmission formula rate updates. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant | | Initial Revenue Requirement Increase/(Decrease) | | Annual Reconciliation Decrease | | Total Revenue Requirement Increase/(Decrease) | | Allowed Return on Rate Base | | Allowed ROE |
| ComEd | | $ | 18 | | | $ | (4) | | | $ | 14 | | | 8.17 | % | | 11.50 | % |
| PECO | | 5 | | | (28) | | | (23) | | | 7.47 | % | | 10.35 | % |
| BGE | | 16 | | | (3) | | | 4 | | | 7.26 | % | | 10.50 | % |
| Pepco | | 2 | | | (46) | | | (44) | | | 7.81 | % | | 10.50 | % |
| DPL | | (4) | | | (40) | | | (44) | | | 7.20 | % | | 10.50 | % |
| ACE | | 5 | | | (25) | | | (20) | | | 7.40 | % | | 10.50 | % |
Sales of Customer Accounts Receivable
On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is 89%-92%, 56%-59%wholly owned by Generation, entered into an accounts receivable financing facility with a number of financial institutions and 32%-35%a commercial paper conduit to sell certain customer accounts receivables. Generation received approximately $500 million of cash in accordance with the initial sale of approximately $1.2 billion receivables. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for 2019, 2020,additional information.
Exelon’s Strategy and Outlook
On February 21, 2021, respectively.Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The percentageseparation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. See Note 26 — Subsequent Events of expectedthe Combined Notes to Consolidated Financial Statements for additional information.
In 2021, the businesses remain focused on maintaining industry leading operational excellence, meeting or exceeding their financial commitments, ensuring timely recovery on investments to enable customer benefits, supporting enactment of clean energy policies, and continued commitment to corporate responsibility.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest
reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean, and affordable energy. Generation’s electricity generation hedgedstrategy is the amount of equivalent sales divided by the expected generation. Expectedto pursue opportunities that provide stable revenues and match supply to customers. Generation leverages its energy generation is the volume ofportfolio to deliver energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such asboth wholesale and retail salescustomers. Generation’s customer-facing activities foster development and delivery of power, optionsother innovative energy-related products and swaps.services for its customers. Generation has beenoperates in well-developed energy markets and will continueemploys an integrated hedging strategy to be proactive in using hedging strategies to mitigatemanage commodity price riskvolatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in subsequentcompetitive energy markets.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS for additional information regarding market and financial factors.
Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses. The Utility Registrants anticipate investing approximately $27 billion over the next four years as well.
Generation procures oilin electric and natural gas through long-terminfrastructure improvements and short-term contractsmodernization projects, including smart grid technology, storm hardening, advanced reliability technologies, and spot-market purchases. Nuclear fueltransmission projects, which is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services,projected to result in an increase to current rate base of approximately $15 billion by the end of 2024. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal, oil and natural gasotherwise meeting customer needs. These investments are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or servicemade at the contracted prices. Approximately 62%lowest reasonable cost to customers.
Competitive Energy Businesses. Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s uranium concentrate requirements from 2019strategy is to ensure appropriate valuation of its generation assets, in part through 2023 are supplied by three producers. Inpublic policy efforts, identify and capitalize on opportunities that match supply to customers as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the eventoption for significant future growth or influence in market development.
Other Key Business Drivers and Management Strategies
Utility Rates and Rate Proceedings
The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of non-performance by these
or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to regulatory proceedings impact the prices under theUtility Registrants’ current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’sfuture results of operations, cash flows, and financial positions. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings.
Power Markets
Price of Fuels
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow themuse of new technologies to recover procurement costsnatural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail customers.power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly
Environmental Legislative and Regulatory Developments
Exelon was actively involved
over the last several years; in the Obama Administration’s development and implementation of environmental regulations for the electric industry,part reflecting an increase in pursuit of its business strategysupply due to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Duestrong natural gas production (due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil fuel plants.shale gas development).
Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.
In particular, the Administration has targeted existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings, and withdrew all technical support documents supporting the calculation. Other regulations that have been specifically identified for review are the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the 2015 National Ambient Air Quality Standard (NAAQS) for ozone. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.
Air Quality
Mercury and Air Toxics Standard RuleStandards (MATS). On December 16, In 2011, the EPA signed a final rule, known as MATS, to reduce emissions of toxichazardous air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known asplants. MATS requires coal-fired electric generationpower plants to achieve high removal rates of mercury, acid gases, and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. The initial compliance deadlineIn 2016, in response to meet the new standards was April 16, 2015; however, facilities may have been granted an additional one or two-year extension in limited cases. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On appeal, the U.S.a Supreme Court decided in June 2015 thatdecision requiring the EPA unreasonably refused to consider costs in determining whether it was appropriate and necessary to regulate power plant emissions of hazardous air pollutants, the EPA issued a supplemental finding that, after considering costs, it remained appropriate and necessary. On May 22, 2020, the EPA reversed course, publishing a final rule revoking the "appropriate and necessary" finding underpinning MATS. A coal mining company filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit seeking vacatur of MATS based on the EPA’s May 22, 2020 finding; on September 11, 2020, the U.S. Court of Appeals for the D.C. Circuit granted a motion by Exelon and two other
entities to intervene in that lawsuit to defend MATS, and on September 28, 2020, the U.S. Court of Appeals for the D.C. Circuit issued an Executive Order holding this portion of the MATS litigation in abeyance. On July 21, 2020, Exelon and two other entities filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit challenging the EPA’s May 22, 2020 rescission of the appropriate and necessary finding underpinning MATS. This portion of the case is also being held in abeyance in response to the DOJ’s motion filed February 12, 2021. On January 20, 2021, President Biden issued an Executive Order directing the EPA to reconsider its May 22, 2020 recission by August 2021; the EPA will likely re-affirm the finding that it is appropriate and necessary to regulate power plant emissions of hazardous air pollutants emitted by electric utilities. The U.S. Supreme Court, however, did not vacate the rule; rather, it was remandedpollutants. As a result, this litigation is likely to the D.C. Circuit Court to take further action consistent with the U.S. Supreme Court’s opinion on this single issue. On April 27, 2017, the D.C. Circuit granted EPA’s motion to hold the litigationbe rendered moot, and MATS will likely remain in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s EO discussed above. Following EPA’s review and determination of its course of action for the MATS rule, the parties will have 30 days to file motions on future proceedings. Notwithstanding the Court’s order to hold the litigation in abeyance, the MATS rule remains in effect. Exelon will continue to participateplace in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule. On December 28, 2018, the EPA proposed to revoke the "appropriate and necessary" finding underpinning the MATS rule. While the proposal would leave in place the rule, it would leave it vulnerable to future legal challenge.
Clean Power Plan. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. On October 10, 2017, EPA issued a proposed rule to repeal the CPP in its entirety, based on a proposed change in the Agency’s legal interpretation of Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG emissions. Subsequently, on August 31, 2018, EPA proposed its Affordable Clean Energy Rule (ACE), which would replace the CPP with revised emission guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants.
2015 Ozone National Ambient Air Quality Standards (NAAQS). On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. EPA did not meet the October 1, 2017 deadline to promulgate initial designations for areas in attainment or non-attainment of the standard. A number of states and environmental organizations have notified the EPA of their intent to file suit to compel EPA to issue the designations.
Climate Change. Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In the absence of Federal legislation, the EPA is moving forward with the regulation of GHG emissions under the Clean Air Act. In addition, there have been recent developments in the international regulation of GHG emissions pursuant to the United Nations Framework Convention on Climate Change (“UNFCCC” or “Convention”). See ITEM 1. BUSINESS, "Global Climate Change" for additional information.interim.
Water Quality
Under the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated, and permits must be renewed periodically. Certain of Exelon's facilities discharge stormwater, industrial wastewater, and/or cooling water into waterways and are therefore subject to these regulations and operate under NPDES permits.
Clean Water Act Section 316(b) is implemented through the NDPES program and requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts and is implemented through state-level NPDES permit programs. All ofimpacts. Generation’s power generation facilities with cooling water intake systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g.,EPA’s Section 316(b) regulations finalized in 2014; the regulation’s requirements have been or will be addressed through renewal of these facilities’ NPDES permits. Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, Generation cannot estimate the effect that compliance with the EPA’s 2014 rule will have on the operation of its generating facilities and its financial statements. Should a state permitting director determine that a facility must install cooling towers)towers to comply with the rule, that facility’s economic viability could be called into question. However, the final rule does not mandate cooling towers and allows state permitting directors to require alternative, less costly technologies and/or operational measures, based on a site-specific assessment of the feasibility, costs, and benefits of available options.
On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers and allows Salem to continue to operate utilizing the existing cooling water system with certain required system modifications. However, the permit is being challenged by an environmental organization, and if successful, could result in additional costs for Clean Water Act compliance. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility.
Under Clean Water Act Section 404 and state laws and regulations, the Registrants may be required to obtain permits for projects involving dredge or fill activities in Waters of the United States.
Where Registrants’ facilities are potentially most affected by recent changesrequired to secure a federal license or permit for activities that may result in a discharge to covered waters, they may be required to obtain a state water quality certification under Clean Water Act section 401.
Generation is also subject to the regulations. For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mystic 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities,jurisdiction of the Delaware River Basin Commission and Salem. See ITEM 1. BUSINESS, "Water Quality" for additional information.the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage.
Solid and Hazardous Waste and Environmental Remediation
In October 2015,CERCLA provides for response and removal actions coordinated by the first federal regulationEPA in the event of threatened releases of hazardous substances and authorizes the EPA either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of hazardous waste at sites, many of which are listed by the EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight. Most states have also enacted statutes that contain provisions substantially similar to CERCLA. Such statutes apply in many states where the Registrants currently own or
operate, or previously owned or operated, facilities, including Delaware, Illinois, Maryland, New Jersey, and Pennsylvania and the District of Columbia. In addition, RCRA governs treatment, storage and disposal of coal combustion residuals (CCR) from power plants became effective. solid and hazardous wastes and cleanup of sites where such activities were conducted.
The rule classifies CCR as non-hazardous waste under RCRA.Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with these Federal and state environmental laws. Under these laws, the regulation, CCR will continue to be regulated by most states subject to coordination with the federal regulations. Generation has previously recorded accruals consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements thatRegistrants may be asserted underliable for the new federal regulations for coal ash disposal sitescosts of remediating environmental contamination of property now or formerly owned by Generation. For these reasons, Generation is unablethem and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. The Registrants and their subsidiaries are, or could become in the future, parties to predict whetherproceedings initiated by the EPA, state agencies, and/or other responsible parties under CERCLA and RCRA or similar state laws with respect to what extent ita number of sites or may ultimatelyundertake to investigate and remediate sites for which they may be held responsiblesubject to enforcement actions by an agency or third-party.
ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover environmental remediation costs of the MGP sites through a provision within customer rates. BGE, ACE, Pepco, and DPL do not have material contingent liabilities relating to MGP sites. The amount to be expended in 2021 for compliance with environmental remediation related to contamination at former MGP sites and other costs relatinggas purification sites is estimated to formerly owned coal ash disposal sites underbe approximately $35 million which consists primarily of $30 million at ComEd.
As of December 31, 2020, the new regulations.Registrants have established appropriate contingent liabilities for environmental remediation requirements. In addition, the Registrants may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.
See Note 223 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ environmental matters, remediation efforts, and related impacts to the Registrants’ Consolidated Financial Statements.
Information about our Executive Officers as of February 24, 2021
Exelon
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Crane, Christopher M. | | 62 | | | Chief Executive Officer, Exelon; | | 2012 - Present |
| | | | | | |
| | | | | | |
| | | | President, Exelon | | 2008 - Present |
| | | | | | |
| | | | | | |
| Cornew, Kenneth W. | | 55 | | | Senior Executive Vice President and Chief Commercial Officer, Exelon; | | 2013 - Present |
| | | | President and CEO, Generation | | 2013 - Present |
| | | | | | |
| | | | | | |
| Butler, Calvin G. | | 51 | | | Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities | | 2019 - Present |
| | | | Chief Executive Officer, BGE | | 2014 - 2019 |
| | | | | | |
| | | | | | |
| | | | | | |
| Dominguez, Joseph | | 58 | | | Chief Executive Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2015 - 2018 |
| | | | | | |
| Glockner, David | | 60 | | | Executive Vice President, Compliance and Audit, Exelon | | 2020 - Present |
| | | | Chief Compliance Officer, Citadel LLC | | 2017 - 2020 |
| | | | Regional Director, U.S. Securities and Exchange Commission | | 2013 - 2017 |
| | | | | | |
| Hanson, Bryan C. | | 55 | | | Executive Vice President and Chief Generation Officer, Generation | | 2020 - Present |
| | | | President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Generation | | 2015 - 2020 |
| | | | | | |
| Innocenzo, Michael A. | | 55 | | | President and Chief Executive Officer, PECO | | 2018 - Present |
| | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 |
| | | | | | |
| Khouzami, Carim V. | | 45 | | | Chief Executive Officer, BGE | | 2019 - Present |
| | | | Senior Vice President, Chief Operating Officer, Exelon Utilities | | 2018 - 2019 |
| | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2016 - 2018 |
| | | | Senior Vice President, Chief Integration Officer, Exelon | | 2014 - 2016 |
| | | | | | |
| Velazquez, David M. | | 61 | | | President and Chief Executive Officer, PHI | | 2016 - Present |
| | | | President and Chief Executive Officer, Pepco, DPL, and ACE | | 2009 - Present |
| | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 |
| | | | | | |
| Von Hoene Jr., William A. | | 67 | | | Senior Executive Vice President and Chief Strategy Officer, Exelon | | 2012 - Present |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| | | | | | |
| Nigro, Joseph | | 56 | | | Senior Executive Vice President and Chief Financial Officer, Exelon | | 2018 - Present |
| | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2013 - 2018 |
| | | | | | |
| Souza, Fabian E. | | 50 | | | Senior Vice President and Corporate Controller, Exelon | | 2018 - Present |
| | | | Senior Vice President and Deputy Controller, Exelon | | 2017 - 2018 |
| | | | Vice President, Controller and Chief Accounting Officer, The AES Corporation | | 2015 - 2017 |
Generation
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Crane, Christopher M. | | 62 | | | Principle Executive Officer, Generation | | 2020 - Present |
| | | | Chief Executive Officer, Exelon; | | 2012 - Present |
| | | | President, Exelon | | 2008 - Present |
| | | | | | |
| Cornew, Kenneth W. | | 55 | | | Senior Executive Vice President and Chief Commercial Officer, Exelon; | | 2013 - Present |
| | | | President and Chief Executive Officer, Generation | | 2013 - Present |
| | | | | | |
| | | | | | |
| Swahl, William | | 51 | | | Senior Vice President, Generation; Chief Operating Officer, Exelon Power | | 2021 - Present |
| | | | Vice President, Generation; Vice President, Mid-Atlantic Operations, Exelon Power | | 2014 - 2020 |
| | | | | | |
| Hanson, Bryan C. | | 55 | | | Executive Vice President and Chief Generation Officer, Generation | | 2020 - Present |
| | | | President and Chief Nuclear Officer, Exelon Nuclear, Senior Vice President, Generation | | 2015 - 2020 |
| | | | | | |
| McHugh, James | | 49 | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2018 - Present |
| | | | Senior Vice President, Portfolio Management & Strategy, Constellation | | 2016 - 2018 |
| | | | Vice President, Portfolio Management, Constellation | | 2012 - 2016 |
| | | | | | |
| Rhoades, David | | 54 | | | Senior Vice President, Generation; President and Chief Nuclear Officer, Exelon Nuclear | | 2020 - Present |
| | | | Chief Operating Officer, Fleet Operations, Exelon Nuclear | | 2015 - 2020 |
| | | | | | |
| Wright, Bryan P. | | 54 | | | Senior Vice President and Chief Financial Officer, Generation | | 2013 - Present |
| | | | | | |
| | | | | | |
| | | | | | |
| Bauer, Matthew N. | | 44 | | | Vice President and Controller, Generation | | 2016 - Present |
| | | | Vice President and Controller, BGE | | 2014 - 2016 |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
ComEd
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Dominguez, Joseph | | 58 | | | Chief Executive Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2015 - 2018 |
| | | | | | |
| Donnelly, Terence R. | | 60 | | | President and Chief Operating Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President and Chief Operating Officer, ComEd | | 2012 - 2018 |
| | | | | | |
| Jones, Jeanne M. | | 41 | | | Senior Vice President, Chief Financial Officer and Treasurer, ComEd | | 2018 - Present |
| | | | Vice President, Finance, Exelon Nuclear | | 2014 - 2018 |
| | | | | | |
| Park, Jane | | 48 | | | Senior Vice President, Customer Operations, ComEd | | 2018 - Present |
| | | | | | |
| | | | Vice President, Regulatory Policy & Strategy, ComEd | | 2016 - 2018 |
| | | | Director, Business Strategy & Technology, ComEd | | 2014 - 2016 |
| | | | | | |
| Gomez, Veronica | | 51 | | | Senior Vice President, Regulatory and Energy Policy and General Counsel, ComEd | | 2017 - Present |
| | | | Vice President and Deputy General Counsel, Litigation, Exelon | | 2012 - 2017 |
| | | | | | |
| Washington, Melissa | | 51 | | | Senior Vice President, Governmental and External Affairs, ComEd | | 2019 - Present |
| | | | | | |
| | | | Vice President, Governmental and External Affairs, ComEd | | 2019 -2019 |
| | | | Vice President, External Affairs and Large Customer Services, ComEd | | 2016 - 2019 |
| | | | Vice President, Corporate Affairs, Exelon Business Services Company | | 2014 - 2016 |
| | | | | | |
| Perez, David | | 51 | | | Senior Vice President, Distribution Operations, ComEd | | 2019 - Present |
| | | | Vice President, Transmission and Substation, ComEd | | 2016 - 2019 |
| | | | Vice President, Regional Operations, ComEd | | 2010 - 2016 |
| | | | | | |
| | | | | | |
PECO
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Innocenzo, Michael A. | | 55 | | | President and Chief Executive Officer, PECO | | 2018 - Present |
| | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 |
| | | | | | |
| McDonald, John | | 63 | | | Senior Vice President and Chief Operations Officer, PECO | | 2018 - Present |
| | | | Vice President, Integration, PHI | | 2016 - 2018 |
| | | | Vice President, Technical Services | | 2006 - 2016 |
| Stefani, Robert J. | | 47 | | | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2018 - Present |
| | | | Vice President, Corporate Development, Exelon | | 2015 - 2018 |
| | | | | | |
| Murphy, Elizabeth A. | | 61 | | | Senior Vice President, Governmental and External Affairs, PECO | | 2016 - Present |
| | | | Vice President, Governmental and External Affairs, PECO | | 2012 - 2016 |
| | | | | | |
| | | | | | |
| Webster Jr., Richard G. | | 59 | | | Vice President, Regulatory Policy and Strategy, PECO | | 2012 - Present |
| | | | | | |
| | | | | | |
| Williamson, Olufunmilayo | | 42 | | | Senior Vice President, Customer Operations, PECO | | 2020 - Present |
| | | | Senior Vice President, Chief Commercial Risk Officer, Exelon | | 2017 - 2020 |
| | | | Vice President, Commercial Risk Management, Exelon | | 2015 - 2017 |
| | | | | | |
| Gay, Anthony | | 55 | | | Vice President and General Counsel, PECO | | 2019 - Present |
| | | | | | |
| | | | Vice President, Governmental and External Affairs, PECO | | 2016 - 2019 |
| | | | Associate General Counsel, Exelon | | 2010 - 2016 |
| | | | | | |
BGE
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Khouzami, Carim V. | | 45 | | | Chief Executive Officer, BGE | | 2019 - Present |
| | | | Senior Vice President, Chief Operating Officer, Exelon Utilities | | 2018 - 2019 |
| | | | Senior Vice President, Chief Financial Officer, Exelon Utilities | | 2016 - 2018 |
| | | | Senior Vice President, Chief Integration Officer, Exelon | | 2014 - 2016 |
| | | | | | |
| Woerner, Stephen J. | | 53 | | | President, BGE | | 2014 - Present |
| | | | Chief Operating Officer, BGE | | 2012 - Present |
| | | | | | |
| | | | | | |
| Vahos, David M. | | 48 | | | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present |
| | | | Vice President, Chief Financial Officer and Treasurer, BGE | | 2014 - 2016 |
| | | | | | |
| | | | | | |
| Núñez, Alexander G. | | 49 | | | Senior Vice President, Regulatory Affairs and Strategy, BGE | | 2020 - Present |
| | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - 2020 |
| | | | Vice President, Governmental and External Affairs, BGE | | 2013 - 2016 |
| | | | | | |
| Case, Mark D. | | 59 | | | Vice President, Strategy and Regulatory Affairs, BGE | | 2012 - Present |
| | | | | | |
| | | | | | |
| Oddoye, Rodney | | 44 | | | Senior Vice President, Governmental and External Affairs, BGE | | 2020 - Present |
| | | | Vice President, Customer Operations, BGE | | 2018 - 2020 |
| | | | Director, Northeast Regional Electric Operations, BGE | | 2016 - 2018 |
| | | | Director, Financial Operations, BGE | | 2015 - 2016 |
| | | | | | |
| Olivier, Tamla | | 48 | | | Senior Vice President, Customer Operations, BGE | | 2020 - Present |
| | | | Senior Vice President, Constellation NewEnergy, Inc. | | 2016 - 2020 |
| | | | VP, Human Resources, Exelon Business Services Company | | 2012 - 2016 |
| | | | | | |
| Corse, John | | 60 | | | Vice President and General Counsel, BGE | | 2018 - Present |
| | | | Associate General Counsel, Exelon | | 2012 - 2018 |
PHI, Pepco, DPL, and ACE
| | | | | | | | | | | | | | | | | | | | |
| Name | | Age | | Position | | Period |
| Velazquez, David M. | | 61 | | | President and Chief Executive Officer, PHI | | 2016 - Present |
| | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 |
| | | | President and Chief Executive Officer, Pepco, DPL, and ACE | | 2009 - Present |
| | | | | | |
| Anthony, J. Tyler | | 56 | | | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE | | 2016 - Present |
| | | | Senior Vice President, Distribution Operations, ComEd | | 2010 - 2016 |
| | | | | | |
| Barnett, Phillip S. | | 57 | | | Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL, and ACE | | 2018 - Present |
| | | | Senior Vice President and Chief Financial Officer, PECO | | 2007 - 2018 |
| | | | Treasurer, PECO | | 2012 - 2018 |
| | | | | | |
| Lavinson, Melissa | | 51 | | | Senior Vice President, Governmental & External Affairs, PHI, Pepco, DPL, and ACE | | 2018 - Present |
| | | | Vice President, Federal Affairs and Policy and Chief Sustainability Officer, PG&E Corporation | | 2015 - 2018 |
| | | | | | |
| Stark, Wendy E. | | 48 | | | Senior Vice President, Legal and Regulatory Strategy and General Counsel, PHI, Pepco, DPL, and ACE | | 2019 - Present |
| | | | Vice President and General Counsel, PHI, Pepco, DPL, and ACE | | 2016 - 2018 |
| | | | Deputy General Counsel, Pepco Holdings, Inc. | | 2012 - 2016 |
| | | | | | |
| McGowan, Kevin M. | | 59 | | | Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL, and ACE | | 2016 - Present |
| | | | Vice President, Regulatory Affairs, Pepco Holdings, Inc. | | 2012 - 2016 |
| | | | | | |
| Dickens, Derrick | | 56 | | | Senior Vice President, Customer Operations, PHI | | 2020 - Present |
| | | | Vice President, Technical Services, BGE | | 2016 - 2020 |
| | | | Director, Advanced Meter Infrastructure, PECO | | 2012 - 2016 |
| | | | | | |
| Humphrey, Marissa | | 41 | | Vice President, Regulatory Policy and Strategy, PHI, DPL, and ACE | | 2021 - Present |
| | | | Vice President Finance, Exelon Utilities | | 2019 - 2020 |
| | | | Vice President, Finance, PHI | | 2016 - 2019 |
| | | | | | |
Each of the Registrants operates in a complex market and regulatory environment that involves significant risks, many of which are beyond that Registrant’s direct control. Such risks, which could negatively affect one or more of the Registrants’ consolidated financial statements, fall primarily under the categories below:
Market and Financial Factors primarily include:
•the price of fuels, in particular the price of natural gas, which affects power prices,
•the generation resources in the markets in which the Registrants operate,
•the demand for electricity, reliability of service, and affordability in the markets where the Registrants conduct their business,
•the ability of the Registrants to operate their respective generating and transmission and distribution assets, their ability to access capital markets, and the impacts on their results of operations due to the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19),
•the impacts of on-going competition, and
•emerging technologies and business models, including those related to climate change mitigation and transition to a low carbon economy.
Regulatory, Legislative, and Legal Factors primarily include changes to, and compliance with, the laws and regulations that govern:
•the design of power markets,
•ZEC programs,
•utility regulatory business models,
•environmental and climate policy, and
•tax policy.
Operational Factors primarily include:
•changes in the global climate could produce extreme weather events, which could put the Registrant’s facilities at risk, and such changes could also affect the levels and patterns of demand for energy and related services,
•the safe, secure, and effective operation of Generation’s nuclear facilities and the ability to effectively manage the associated decommissioning obligations,
•the ability of the Registrants to maintain the reliability, resiliency, and safety of their energy delivery systems, which could affect the operating costs of the Registrants and the opinions of their customers and regulators, and
•physical and cyber security risks for the Registrants as the owner-operators of generation, transmission, and distribution facilities and as participants in commodities trading.
Risks Related to the Planned Separation primarily include:
•the timing and conditions associated with required regulatory approvals, which may affect the costs to achieve the separation and its timing,
•challenges to achieving the benefits of separation, including maintaining investment grade credit ratings, and
•the risk that the separation could be treated as a taxable transaction to both Exelon and its shareholders.
There may be further risks and uncertainties that are not presently known or that are not currently believed by the Registrants to be material that could negatively affect its consolidated financial statements in the future.
Market and Financial Factors
Generation is exposed to price volatility associated with both the wholesale and retail power markets and the procurement of nuclear and fossil fuel (Exelon and Generation).
Generation is exposed to commodity price risk for the unhedged portion of its electricity generation supply portfolio. Generation’s earnings and cash flows are therefore exposed to variability of spot and forward market prices in the markets in which it operates.
Price of Fuels. The spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the market during that hour. Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit.
Demand and Supply. The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs could each depress demand. In addition, in some markets, the supply of electricity could often exceed demand during some hours of the day, resulting in loss of revenue for base-load generating plants such as Generation's nuclear plants. Conversely, new demand sources such as electrification of transportation could increase demand and change demand patterns.
Retail Competition. Generation’s retail operations compete for customers in a competitive environment, which affects the margins that Generation can earn and the volumes that it is able to serve. In periods of sustained low natural gas and power prices and low market volatility, retail competitors can aggressively pursue market share because the barriers to entry can be low and wholesale generators (including Generation) use their retail operations to hedge generation output.
The impact of sustained low market prices or depressed demand and over-supply could be emphasized given Generation’s concentration of base-load electric generating capacity within primarily two geographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect Generation’s ability to fund regulated utility growth for the benefit of customers, reduce debt and provide attractive shareholder returns. In addition, such conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Generation's financial statements primarily through accelerated depreciation and amortization expenses and one-time charges. See Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Cost of Fuel. Generation depends on nuclear fuel and fossil fuels to operate most of its generating facilities. The supply markets for nuclear fuel, natural gas, and oil are subject to price fluctuations, availability restrictions, and counterparty default.
Market Designs. The wholesale markets vary from region to region with distinct rules, practices, and procedures. Changes in these market rules, problems with rule implementation, or failure of any of these markets could adversely affect Generation’s business. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect on market stability.
The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry (All Registrants).
Some of these technologies include, but are not limited to, further development or applications of technologies related to shale gas production, renewable energy technologies, energy efficiency, distributed generation, and energy storage devices. Such developments could affect the price of energy, levels of customer-owned generation, customer expectations, and current business models and make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy. Each of these factors could affect the Registrants’ consolidated financial statements through, among other things, reduced operating revenues, increased operating and maintenance expenses, increased capital expenditures, and potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.
Market performance and other factors could decrease the value of NDT funds and employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants).
Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of the investments held within Generation’s NDTs and Exelon’s employee benefit plan trusts. The Registrants have significant obligations in these areas and Exelon and Generation hold substantial assets in these trusts to meet those obligations. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below the Registrants’ projected return rates. A decline in the market value of the NDT fund investments could increase Generation’s funding requirements to
decommission its nuclear plants. A decline in the market value of the pension and OPEB plan assets would increase the funding requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the costs and funding requirements of the obligations related to the pension and OPEB plans. See Note 10 — Asset Retirement Obligations and Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants could be negatively affected by unstable capital and credit markets and increased volatility in commodity markets (All Registrants).
The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs. Disruptions in the capital and credit markets in the United States or abroad could negatively affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives, or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, Generation’s ability to hedge effectively its generation portfolio, changes to Generation’s hedging strategy in order to reduce collateral posting requirements, or a reduction in dividend payments or other discretionary uses of cash. In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2020, approximately 23%, 19%, and 18% of the Registrants’ available credit facilities were with European, Canadian, and Asian banks, respectively. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities.
The strength and depth of competition in energy markets depend heavily on active participation by multiple trading parties, which could be negatively affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that could affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power, including the requirement of long-term contracts.
If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties, it would be required to provide significant amounts of collateral under its agreements with counterparties and could experience higher borrowing costs (All Registrants).
Generation’s business is subject to credit quality standards that could require market participants to post collateral for their obligations. If Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating) or otherwise fail to satisfy the credit standards of trading counterparties, it would be required under its hedging arrangements to provide collateral in the form of letters of credit or cash, which could have a material adverse effect upon its liquidity. The amount of collateral required to be provided by Generation at any point in time depends on a variety of factors, including (1) the notional amount of the applicable hedge, (2) the nature of counterparty and related agreements, and (3) changes in power or other commodity prices. In addition, if Generation were downgraded, it could experience higher borrowing costs as a result of the downgrade. Changes in ratings methodologies by the credit rating agencies could also have a negative impact on the ratings of Generation.
Generation has project-specific financing arrangements and must meet the requirements of various agreements relating to those financings. Failure to meet those arrangements could give rise to a project-specific financing default which, if not cured or waived, could result in the specific project being required to repay the associated
debt or other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have broad remedies, including rights to foreclose against the project assets and related collateral or to force the Exelon subsidiaries in the project-specific financings to enter into bankruptcy proceedings. The impact of bankruptcy could result in the impairment of certain project assets.
The Utility Registrants' operating agreements with PJM and PECO's, BGE's, and DPL's natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO, BGE, and DPL, with respect to their natural gas supply contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. If the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade. In addition, changes in ratings methodologies by the agencies could also have an adverse negative impact on the ratings of the Utility Registrants.
The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters — Market Conditions and Security Ratings for additional information regarding the potential impacts of credit downgrades on the Registrants’ cash flows.
Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities (Exelon and Generation).
Generation’s asset-based power position as well as its power marketing, fuel procurement, and other commodity trading activities expose Generation to risks of commodity price movements. Generation buys and sells energy and other products and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolio. Generation is exposed to volatility in financial results for unhedged positions as well as the risk of ineffective hedges. Generation attempts to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations could be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its commodity trading activities and risk management decisions could have on its consolidated financial statements.
Financial performance and load requirements could be negatively affected if Generation is unable to effectively manage its power portfolio (Exelon and Generation).
A significant portion of Generation’s power portfolio is used to provide power under procurement contracts with the Utility Registrants and other customers. To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale power markets. To the extent its power portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale power markets. Generation’s financial results could be negatively affected if it is unable to cost-effectively meet the load requirements of its customers, manage its power portfolio or effectively address the changes in the wholesale power markets.
The impacts of significant economic downturns or increases in customer rates, could lead to decreased volumes delivered and increased expense for uncollectible customer balances (All Registrants).
The impacts of significant economic downturns on the Utility Registrants' customers, such as less demand for products and services provided by commercial and industrial customers, and the related regulatory limitations on residential service terminations, could result in an increase in the number of uncollectible customer balances. Further, increases in customer rates, including those related to increases in purchased power and natural gas prices, could result in declines in customer usage and lower revenues for the Utility Registrants that do not have decoupling mechanisms.
Generation's customer-facing energy delivery activities face similar economic downturn risks, such as lower volumes sold and increased expense for uncollectible customer balances.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information of the Registrants’ credit risk.
The Registrants' results could be negatively affected by the impacts of COVID-19 (All Registrants).
COVID-19 is an evolving situation that could lead to extended disruption of economic activity in the Registrants’ respective markets. COVID-19 could negatively affect the Registrants’ ability to operate their respective generating and transmission and distribution assets, their ability to access capital markets, and their results of operations. The Registrants cannot predict the extent of the impacts of COVID-19, which will depend on future developments and which are highly uncertain. See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Executive Overview for additional information.
The Registrants could be negatively affected by the impacts of weather (All Registrants).
Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting revenues at PECO, DPL Delaware, and ACE. Due to revenue decoupling, BGE, Pepco, and DPL Maryland recognize revenues at MDPSC and DCPSC-approved levels per customer, regardless of what actual distribution volumes are for a billing period and are not affected by actual weather with the exception of major storms. ComEd’s customer rates are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenue.
Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems, and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customer demand. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant.
Generation’s operations are also affected by weather, which affects demand for electricity as well as operating conditions. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation could require greater resources to meet its contractual commitments. Extreme weather conditions or storms could affect the availability of generation and its transmission, limiting Generation’s ability to source or send power to where it is sold. In addition, drought-like conditions limiting water usage could impact Generation’s ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could cause Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when markets are weak.
Climate change projections suggest increases to summer temperature and humidity trends, as well as more erratic precipitation and storm patterns over the long-term in the areas where Registrants have generation, transmission, and distribution assets. The frequency in which weather conditions emerge outside the current expected climate norms could contribute to weather-related impacts discussed above.
Long-lived assets, goodwill, and other assets could become impaired (All Registrants).
Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. In addition, Exelon, ComEd, and PHI have material goodwill balances.
The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered.
ComEd and PHI perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Regulatory actions or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco’s, DPL’s, and ACE’s business, and the fair value of debt, could potentially result in future impairments of Exelon’s, ComEd's, and PHI’s goodwill.
An impairment would require the Registrants to reduce the carrying value of the long-lived asset or goodwill to fair value through a non-cash charge to expense by the amount of the impairment. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, Note 8 — Property, Plant, and Equipment, Note 12 — Asset Impairments and Note 13 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset impairments and goodwill impairments.
The Registrants could incur substantial costs in the event of non-performance by third-parties under indemnification agreements, or when the Registrants have guaranteed their performance. Generation is exposed to other credit risks in the power markets that are beyond its control (All Registrants).
The Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations. Each of the Utility Registrants has transferred its former generation business to a third party and in each case the transferee has agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO, and BGE transferred their generating assets to Generation, Generation assumed certain of ComEd’s, PECO’s, and BGE's rights and obligations with respect to their former generation businesses. Further, ComEd, PECO, and BGE have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO, or BGE for certain obligations related to their respective former generation businesses that have been assumed by Generation as part of the restructuring. If the third-party, Generation, or the transferee of Pepco's, DPL's, or ACE’s generation facilities experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims. In addition, the Utility Registrants have residual liability under certain laws in connection with their former generation facilities.
The Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets and they could incur substantial costs to fulfill their obligations under these indemnities.
The Registrants have issued guarantees of the performance of third parties, which obligate the Registrants to perform in the event that the third parties do not perform. In the event of non-performance by those third parties, the Registrants could incur substantial cost to fulfill their obligations under these guarantees.
In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money or are obligated to purchase energy or fuel from Generation, will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent amounts, if any, were already paid to the counterparties. In the spot markets, Generation is
exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, Generation’s retail sales subject it to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer.
Regulatory, Legislative, and Legal Factors
Federal or state legislative or regulatory actions could negatively affect the scope and functioning of the wholesale markets (Exelon and Generation).
Approximately 70% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the area encompassed by PJM. Generation’s future results of operations are impacted by (1) FERC’s and PJM's support for policies that favor the preservation of competitive wholesale power markets and recognize the value of zero-carbon electricity and resiliency and for states' energy objectives and policies (2) the absence of material changes to market structures that would limit or otherwise negatively affect Exelon or Generation. Generation could also be affected by state laws, regulations, or initiatives to subsidize existing or new generation.
FERC’s requirements for market-based rate authority could pose a risk that Generation may no longer satisfy FERC’s tests for market-based rates.
The Registrants’ are highly regulated and could be negatively affected by regulatory and legislative actions (All Registrants).
Substantially all aspects of the businesses of the Registrants are subject to comprehensive Federal or state regulation and legislation.
Generation’s consolidated financial statements are significantly affected by its sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated rates and Federal and state regulatory and legislative developments related to emissions, climate change, capacity market mitigation, energy price information, resilience, fuel diversity, and RPS. Legislative and regulatory efforts in Illinois, New York, and New Jersey to preserve the environmental attributes and reliability benefits of zero-emission nuclear-powered generating facilities through ZEC programs are or could be subject to legal and regulatory challenges and, if overturned, could result in the early retirement of certain of Generation’s nuclear plants. See Note 3 — Regulatory Matters and Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs for the retail purchase and distribution of power and natural gas to their customers.
Fundamental changes in regulations or other adverse legislative actions affecting the Registrants’ businesses would require changes in their business planning models and operations. The Registrants cannot predict when or whether legislative and regulatory proposals could become law or what their effect will be on the Registrants.
Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy, and subject to appeal, which lead to uncertainty as to the ultimate result and which could introduce time delays in effectuating rate changes (Exelon and the Utility Registrants).
The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of
energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, credit losses, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs. In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives, or franchise agreements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants to recover their costs or earn an adequate return. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.
NRC actions could negatively affect the operations and profitability of Generation’s nuclear generating fleet (Exelon and Generation).
Regulatory risk. A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or could result in increased operating or decommissioning costs. Events at nuclear plants owned by others, as well as those owned by Generation, could cause the NRC to initiate such actions.
Spent nuclear fuel storage. The approval of a national repository for the storage of SNF and the timing of such a facility opening, will significantly affect the costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse Generation for these costs.
Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect Generation’s ability to fully decommission its nuclear units. Generation cannot predict what, if any, fee may be established in the future for SNF disposal. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the SNF obligation.
The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of PJM’s RTEP and NERC compliance requirements (All Registrants).
The Registrants as users, owners, and operators of the bulk power transmission system, including Generation and the Utility Registrants, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. PECO, BGE, and DPL, as operators of natural gas distribution systems, are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DPSC, and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Registrants were found not to be in compliance with the Federal and state mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants).
The businesses that the Registrants operate are subject to extensive environmental regulation and legislation by local, state, and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions, hazardous and solid waste, and activities affecting surface waters, groundwater, and aquatic and other species. Violations of these requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages, or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property
contaminated by hazardous substances they generated or released. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future. See ITEM 1. BUSINESS — Environmental Regulation for additional information.
The Registrants could be negatively affected by challenges to tax positions taken, tax law changes, and the inherent difficulty in quantifying potential tax effects of business decisions. (All Registrants).
The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Significant Accounting Policies and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants could be negatively affected by federal and state RPS and/or energy conservation legislation, along with energy conservation by customers (All Registrants).
Changes to current state legislation or the development of Federal legislation that requires the use of clean, renewable, and alternate fuel sources could significantly impact Generation and the Utility Registrants, especially if timely cost recovery is not allowed for Utility Registrants. The impact could include increased costs and increased rates for customers.
Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, could increase capital expenditures and could significantly impact the Utility Registrants consolidated financial statements if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to a decline in the revenues of the Registrants. See ITEM 1. BUSINESS — Environmental Regulation — Renewable and Clean Energy Standards for additional information.
Generation’s affiliation with the Utility Registrants, together with the presence of a substantial percentage of Generation’s physical asset base within the Utility Registrants' service territories, could increase Generation’s cost of doing business to the extent future complaints or challenges regarding the Utility Registrants' retail rates result in settlements or legislative or regulatory requirements funded in part by Generation (Exelon and Generation).
Generation has significant generating resources within the service areas of the Utility Registrants and makes significant sales to each of them. Those facts tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators, and advocacy groups are aware of Generation’s affiliation with the Utility Registrants and its sales to each of them. In periods of rising utility rates, particularly when driven by increased costs of energy production and supply, those officials and advocacy groups could question or challenge costs and transactions incurred by the Utility Registrants with Generation, irrespective of any previous regulatory processes or approvals underlying those transactions. These challenges could increase the time, complexity, and cost of the associated regulatory proceedings, and the occurrence of such challenges could subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. In addition, government officials and legislators could seek ways to force Generation to contribute to efforts to mitigate potential or actual rate increases, through measures such as generation-based taxes.
The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences (All Registrants).
The Registrants could be the subject of public criticism. Adverse publicity of this nature could render public service commissions and other regulatory and legislative authorities less likely to view energy companies such as Exelon and its subsidiaries in a favorable light, and could cause Exelon and its subsidiaries to be susceptible
to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements (e.g. disallowances of costs, lower ROEs).
Legal proceedings could result in a negative outcome, which the Registrants cannot predict (All Registrants).
The Registrants are involved in legal proceedings, claims, and litigation arising out of their business operations. The material ones are summarized in Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue, or restrict existing business activities.
Exelon and ComEd have received requests for information related to an SEC investigation into their lobbying activities. The outcome of the investigations could have a material adverse effect on their reputation and consolidated financial statements (Exelon and ComEd).
On October 22, 2019, the SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the state of Illinois. Exelon and ComEd have cooperated fully, including by providing all information requested by the SEC, and intend to continue to cooperate fully and expeditiously with the SEC. The outcome of the SEC’s investigation cannot be predicted and could subject Exelon and ComEd to civil penalties, sanctions, or other remedial measures. Any of the foregoing, as well as the appearance of non-compliance with anti-corruption and anti-bribery laws, could have an adverse impact on Exelon’s and ComEd’s reputations or relationships with regulatory and legislative authorities, customers, and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
If ComEd violates its Deferred Prosecution Agreement announced on July 17, 2020, it could have an adverse effect on the reputation and consolidated financial statements of Exelon and ComEd (Exelon and ComEd).
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including, but not limited to, the following: (i) payment to the United States Treasury of $200 million; (ii) continued full cooperation with the government’s investigation; and (iii) ComEd’s adoption and maintenance of remedial measures involving compliance and reporting undertakings as specified in the DPA. If ComEd is found to have breached the terms of the DPA, the USAO may elect to prosecute, or bring a civil action against, ComEd for conduct alleged in the DPA or known to the government, which could result in fines or penalties and could have an adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
Generation’s financial performance could be negatively affected by risks arising from its ownership and operation of hydroelectric facilities (Exelon and Generation).
FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands or connected to the interstate electric grid. Generation cannot predict whether it will receive all the regulatory approvals for the renewed licenses of its hydroelectric facilities. If FERC does not issue new operating licenses for Generation’s hydroelectric facilities or a station cannot be operated through the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation could also lose
revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, could require a substantial increase in capital expenditures, could result in increased operating costs or could render the project uneconomic. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by Generation.
Operational Factors
The Registrants are subject to risks associated with climate change (All Registrants).
The Registrants periodically perform analyses to better understand how climate change could affect their facilities and operations. The Registrants primarily operate in the Midwest and East Coast of the United States, areas that historically have been prone to various types of severe weather events, such that the Registrants have well-developed response and recovery programs based on these historical events. However, the Registrants’ physical facilities could be placed at greater risk of damage should changes in the global climate impact temperature and weather patterns, resulting in more intense, frequent and extreme weather events, unprecedented levels of precipitation, sea level rise, increased surface water temperatures, and/or other effects. In addition, changes to the climate may impact levels and patterns of demand for energy and related services, which could affect Registrants’ operations. Over time, the Registrants may need to make additional investments to protect facilities from physical climate-related risks and/or adapt to changes in operational requirements as a result of climate change.
The Registrants also periodically perform analyses of potential pathways to reduce power sector and economy-wide GHG emissions to mitigate climate change. To the extent additional GHG reduction regulation or legislation becomes effective at the Federal and/or state levels, the Registrants could incur costs to further limit the GHG emissions from their operations or otherwise comply with applicable requirements. To the extent such additional regulation or legislation does not become effective, the potential competitive advantage offered by Registrant’s low-carbon emission profile may be reduced. See ITEM 1. BUSINESS — Climate Change Mitigation.
Generation’s financial performance could be negatively affected by matters arising from its ownership and operation of nuclear facilities (Exelon and Generation).
Nuclear capacity factors. Capacity factors for nuclear generating units, significantly affect Generation’s results of operations. Lower capacity factors could decrease Generation’s revenues and increase operating costs by requiring Generation to produce additional energy from primarily its fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to committed third-party sales, including the Utility Registrants. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations.
Nuclear refueling outages. In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refueling outages, along with their duration, could have a significant impact on Generation’s results of operations. When refueling outages last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease, and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales and higher operating and maintenance costs.
Nuclear fuel quality. The quality of nuclear fuel utilized by Generation could affect the efficiency and costs of Generation’s operations. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs, and/or increased costs due to decreased generation capabilities.
Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation must shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. Generation could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation could lose revenue and incur increased fuel and purchased power expense to meet supply commitments.
For plants operated but not wholly owned by Generation, Generation could also incur liability to the co-owners. For nuclear plants not operated and not wholly owned by Generation, from which Generation receives a portion of the plants’ output, Generation’s results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants. Additionally, poor operating
performance at nuclear plants not owned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy. In addition, closure of generating plants owned by others, or extended interruptions of generating plants, or failure of transmission lines, could affect transmission systems that could adversely affect the sale and delivery of electricity in markets served by Generation.
Nuclear major incident risk and insurance. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by Generation or owned by others, could exceed Generation’s resources, including insurance coverage. Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation’s nuclear operations. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by Generation. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned by Generation or others, could result in increased regulation and reduced public support for nuclear-fueled energy.
As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance, $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $13.8 billion limit for a single incident.
See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of nuclear insurance.
Decommissioning obligation and funding. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility.
Generation recognizes as a liability the present value of the estimated future costs to decommission its nuclear facilities. The estimated liability is based on assumptions in the approach and timing of decommissioning the nuclear facilities, estimation of decommissioning costs, and Federal and state regulatory requirements. The costs of such decommissioning may substantially exceed such liability, as facts, circumstances or our estimates may change, including changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in Federal or state regulatory requirements on the decommissioning of such facilities, other changes in our estimates or Generation’s ability to effectively execute on its planned decommissioning activities.
Generation makes contributions to certain trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to Generation. While Generation, through PECO, has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from utility customers for any of its other nuclear units if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation would be unable to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units could be negatively affected.
Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income, and the adverse impact to Exelon’s and Generation’s financial statements could be material. Any changes to the existing PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s financial statements could be material.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. If the investments held by Generation’s NDT funds are not sufficient to fund the decommissioning of Generation’s nuclear units, Generation could be required to take steps, such as providing financial guarantees through letters of credit or parent
company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met.
See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants' operating costs are affected by their ability to maintain the availability and reliability of their delivery and operational systems (Exelon and the Utility Registrants).
Failures of the equipment or facilities used in the Utility Registrants' delivery systems could interrupt the electric transmission and electric and natural gas delivery, which could result in a loss of revenues and an increase in maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of AMI, smart grid, or other technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems, or if any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results could be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal and/or external tampering or manipulation of those systems will result in losses that are difficult to detect.
Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers, which could be material.
The Registrants are subject to physical security and cybersecurity risks (All Registrants).
The Registrants face physical security and cybersecurity risks. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural gas utility industry associated with protection of sensitive and confidential information, grid infrastructure, and other energy infrastructures, and such attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of advanced digital technologies increases the potentially unfavorable impacts of such attacks. A security breach of the physical assets or information systems of the Registrants, their competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor, and employee data, trading or other confidential data. The risk of these system-related events and security breaches occurring continues to intensify, and while the Registrants have been, and will likely continue to be, subjected to physical and cyber-attacks, to date none has directly experienced a material breach or disruption to its network or information systems or our service operations. However, as such attacks continue to increase in sophistication and frequency, the Registrants may be unable to prevent all such attacks in the future. If a significant breach were to occur, the reputation of the Registrants could be negatively affected, customer confidence in the Registrants or others in the industry could be diminished, or the Registrants could be subject to legal claims, loss of revenues, increased costs, or operations shutdown. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result.
The Utility Registrants' deployment of smart meters throughout their service territories could increase the risk of damage from an intentional disruption of the system by third parties.
In addition, new or updated security regulations or unforeseen threat sources could require changes in current measures taken by the Registrants or their business operations and could adversely affect their consolidated financial statements.
The Registrants’ employees, contractors, customers, and the general public could be exposed to a risk of injury due to the nature of the energy industry (All Registrants).
Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous environments near the Registrants’ operations. As a result, employees,
contractors, customers, and the general public are at some risk for serious injury, including loss of life. These risks include nuclear accidents, dam failure, gas explosions, pole strikes, and electric contact cases.
Natural disasters, war, acts and threats of terrorism, pandemic, and other significant events could negatively impact the Registrants' results of operations, their ability to raise capital and their future growth (All Registrants).
Generation’s fleet of power plants and the Utility Registrants' distribution and transmission infrastructures could be affected by natural disasters and extreme weather events, which could result in increased costs, including supply chain costs. An extreme weather event within the Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Natural disasters and other significant events increase the risk to Generation that the NRC or other regulatory or legislative bodies could change the laws or regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning, security, and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units.
The impact that potential terrorist attacks could have on the industry and on Exelon is uncertain. The Registrants face a risk that their operations would be direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect their operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these catastrophic events could compromise the physical or cybersecurity of Exelon’s facilities, which could adversely affect Exelon’s ability to manage its business effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession, or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.
The Registrants could be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate Exelon's generating and transmission and distribution assets could be affected.
In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses.
The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability (All Registrants).
The Registrants’ businesses are capital intensive and require significant investments by Generation in electric generating facilities and by the Utility Registrants in transmission and distribution infrastructure projects. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Registrants’ control, and could require significant expenditures to operate efficiently. The Registrants consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources for additional information regarding the Registrants’ potential future capital expenditures.
The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by transmission congestion and failures of neighboring transmission systems (Exelon and the Utility Registrants).
Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission
capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures.
PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. However, service interruptions at other utilities may cause interruptions in the Utility Registrants’ service areas.
The Registrants consolidated financial statements could be negatively affected if they fail to attract and retain an appropriately qualified workforce (All Registrants).
Certain events, such as an employee strike, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, could arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their generation, transmission, and distribution operations.
The Registrants could make acquisitions or investments in new business initiatives and new markets, which may not be successful or achieve the intended financial results (All Registrants).
Generation could continue to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. This could include investment opportunities in renewables, development of natural gas generation, nuclear advisory or operating services for third parties, distributed generation, potential expansion of the existing wholesale gas businesses, and entry into LNG. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered during diligence performed prior to launching an initiative or entering a market. Additionally, it is possible that FERC, state public utility commissions or others could impose certain other restrictions on such transactions. All of these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment.
The Utility Registrants face risks associated with their regulatory-mandated initiatives, such as smart grids and utility of the future. These risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity, and obsolescence of technology. Such initiatives may not be successful.
The Registrants may not realize or achieve the anticipated cost savings through the cost management efforts (All Registrants).
The Registrants’ future financial performance and level of profitability is dependent, in part, on various cost reduction initiatives. The Registrants may encounter challenges in executing these cost reduction initiatives and not achieve the intended cost savings.
Risks Related to the Planned Separation (Exelon and Generation)
The planned separation is contingent upon regulatory approvals and satisfaction of other conditions and may not be completed in accordance with the expected plans or anticipated timeline, or at all, which could negatively affect Exelon’s and Generation’s consolidated financial statements.
Exelon is targeting to complete the separation in the first quarter of 2022, subject to final approval by Exelon’s Board of Directors, a Form 10 registration statement being declared effective by the SEC, regulatory approvals, and satisfaction of other conditions. The planned separation is subject to approval by the FERC, NRC and NYPSC. There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing. If the planned separation is not completed or is delayed, Exelon’s and Generation’s consolidated financial statements may be materially adversely affected, and the market price of Exelon’s common stock may be affected.
The plan to separate into two publicly traded companies will involve significant time and expense, which could disrupt or adversely affect our business.
The planned separation is complex in nature, and unanticipated developments or changes, including challenges in executing the separation, could delay or prevent the completion of the proposed separation, or cause the separation to occur on terms or conditions that are different or less favorable than expected. Additionally, Exelon’s Board of Directors, in its sole and absolute discretion, may decide not to proceed with the separation at any time prior to the distribution date. The process of completing the proposed separation has been and is expected to continue to be time-consuming and involves significant costs and expenses.
The planned separation may not achieve some or all of the anticipated benefits and each separate company following the separation may underperform relative to Exelon’s expectations.
By separating the Utility Registrants and Generation, Exelon is creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separate companies are expected to create value by having the strategic flexibility to focus on their unique customer, market and community priorities. However, the planned separation may not provide such results on the scope or scale that Exelon anticipates, and Exelon and Generation may not realize the anticipated benefits of the planned separation. Failure to do so could have a material adverse effect on the financial statements of each separate company and their respective common stock price.
Following the planned separation, the companies anticipate to maintain investment grade credit ratings. Ratings are based upon assessments of multiple factors, including a company’s credit metrics as well as industry and macroeconomic changes and trends. If a rating agency were to downgrade the rating below investment grade, the separate companies’ borrowing costs would increase and their funding sources could decrease, which could have a material adverse effect on the financial statements of the affected company.
The common stock of the separately publicly traded companies following the separation may collectively trade at a value less than the price at which Exelon’s common stock might have traded had the separation not occurred.
There could be significant liability if the planned spin-off is determined to be a taxable transaction.
Under the separation plan, Exelon shareholders will retain their current shares of Exelon stock and receive a pro-rata distribution of shares of the new company’s stock in a transaction that is expected to be tax-free to Exelon and its shareholders under Sections 355 and 368 of the IRC. Exelon will seek a private letter ruling from the IRS regarding the tax-free nature of the transaction. Exelon will also seek from its tax advisors an opinion with respect to certain U.S. federal income tax consequences of the spin-off. If the planned spin-off ultimately is determined to be taxable, the spin-off could be treated as a taxable dividend to Exelon’s shareholders for U.S. federal income tax purposes, and Exelon’s shareholders could incur significant U.S. federal income tax liabilities. In addition, Exelon would recognize a taxable gain to the extent that the fair market value of the new company’s stock exceeds its tax basis in such stock on the date of the planned separation. Exelon will enter into a Tax Matters Agreement with the new company to address how post-separation issues will be managed between the companies, as well as which company is responsible for taxes imposed as a result of the planned separation, if any.
See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information on the planned separation.
| | | | | |
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
All Registrants
None.
Generation
The following table presents Generation’s interests in net electric generating capacity by station at December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Station(a) | | Location | | No. of
Units | | Percent Owned(b) | | Primary
Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
| Midwest | | | | | | | | | | | | | |
| Braidwood | | Braidwood, IL | | 2 | | | | | Uranium | | Base-load | | 2,386 | | |
| Byron | | Byron, IL | | 2 | | | | | Uranium | | Base-load | | 2,347 | | (e) |
| LaSalle | | Seneca, IL | | 2 | | | | | Uranium | | Base-load | | 2,320 | | |
| Dresden | | Morris, IL | | 2 | | | | | Uranium | | Base-load | | 1,845 | | (e) |
| Quad Cities | | Cordova, IL | | 2 | | | 75 | | | Uranium | | Base-load | | 1,403 | | (f) |
| Clinton | | Clinton, IL | | 1 | | | | | Uranium | | Base-load | | 1,080 | | |
| Michigan Wind 2 | | Sanilac Co., MI | | 50 | | | 51 | | (g) | Wind | | Intermittent | | 46 | | (f) |
| Beebe | | Gratiot Co., MI | | 34 | | | 51 | | (g) | Wind | | Intermittent | | 42 | | (f) |
| Michigan Wind 1 | | Huron Co., MI | | 46 | | | 51 | | (g) | Wind | | Intermittent | | 35 | | (f) |
| Harvest 2 | | Huron Co., MI | | 33 | | | 51 | | (g) | Wind | | Intermittent | | 30 | | (f) |
| Harvest | | Huron Co., MI | | 32 | | | 51 | | (g) | Wind | | Intermittent | | 27 | | (f) |
| Beebe 1B | | Gratiot Co., MI | | 21 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) |
| City Solar | | Chicago, IL | | 1 | | | | | Solar | | Intermittent | | 9 | | |
| Solar Ohio | | Toledo, OH | | 2 | | | | | Solar | | Intermittent | | 4 | | (h) |
| Blue Breezes | | Faribault Co., MN | | 2 | | | | | Wind | | Intermittent | | 3 | | |
| CP Windfarm | | Faribault Co., MN | | 2 | | | 51 | | (g) | Wind | | Intermittent | | 2 | | (f) |
| Southeast Chicago | | Chicago, IL | | 8 | | | | | Gas | | Peaking | | 296 | | (i) |
| Clinton Battery Storage | | Blanchester, OH | | 1 | | | | | Energy Storage | | Peaking | | 10 | | |
| Total Midwest | | | | | | | | | | | | 11,911 | | |
| | | | | | | | | | | | | |
| Mid-Atlantic | | | | | | | | | | | | | |
| Limerick | | Sanatoga, PA | | 2 | | | | | Uranium | | Base-load | | 2,317 | | |
| Peach Bottom | | Delta, PA | | 2 | | | 50 | | | Uranium | | Base-load | | 1,324 | | (f) |
| Salem | | Lower Alloways
Creek Township, NJ | | 2 | | | 42.59 | | | Uranium | | Base-load | | 995 | | (f) |
| Calvert Cliffs | | Lusby, MD | | 2 | | | 50.01 | | (j) | Uranium | | Base-load | | 895 | | (f) |
| Conowingo | | Darlington, MD | | 11 | | | | | Hydroelectric | | Base-load | | 572 | | |
| Criterion | | Oakland, MD | | 28 | | | 51 | | (g) | Wind | | Intermittent | | 36 | | (f) |
| Fair Wind | | Garrett County, MD | | 12 | | | | | Wind | | Intermittent | | 30 | | |
| Solar MC | | Various, MD | | 44 | | | | | Solar | | Intermittent | | 44 | | (h) |
| Fourmile Ridge | | Garrett County, MD | | 16 | | | 51 | | (g) | Wind | | Intermittent | | 20 | | (f) |
| Solar New Jersey 1 | | Various, NJ | | 5 | | | | | Solar | | Intermittent | | 18 | | (h) |
| Solar New Jersey 2 | | Various, NJ | | 2 | | | | | Solar | | Intermittent | | 11 | | (h) |
| Solar Horizons | | Emmitsburg, MD | | 1 | | | 51 | | (g) | Solar | | Intermittent | | 16 | | (f) |
| Solar Maryland | | Various, MD | | 11 | | | | | Solar | | Intermittent | | 8 | | (h) |
| Solar Maryland 2 | | Various, MD | | 3 | | | | | Solar | | Intermittent | | 8 | | (h) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Station(a) | | Location | | No. of
Units | | Percent Owned(b) | | Primary
Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
| JBAB Solar | | District of Columbia | | 4 | | | | | Solar | | Intermittent | | 7 | | (h) |
| Gateway Solar | | Berlin, MD | | 1 | | | | | Solar | | Intermittent | | 7 | | (h) |
| Constellation New Energy | | Gaithersburg, MD | | 2 | | | | | Solar | | Intermittent | | 6 | | (h) |
| Solar Federal | | Trenton, NJ | | 1 | | | | | Solar | | Intermittent | | 5 | | (h) |
| Solar New Jersey 3 | | Middle Township, NJ | | 5 | | | 51 | | (g) | Solar | | Intermittent | | 2 | | (f) |
| Solar DC | | District of Columbia | | 1 | | | | | Solar | | Intermittent | | 1 | | (h) |
| Muddy Run | | Drumore, PA | | 8 | | | | | Hydroelectric | | Intermediate | | 1,070 | | |
| Eddystone 3, 4 | | Eddystone, PA | | 2 | | | | | Oil/Gas | | Peaking | | 760 | | |
| Perryman | | Aberdeen, MD | | 5 | | | | | Oil/Gas | | Peaking | | 404 | | |
| Croydon | | West Bristol, PA | | 8 | | | | | Oil | | Peaking | | 391 | | |
| Handsome Lake | | Kennerdell, PA | | 5 | | | | | Gas | | Peaking | | 268 | | |
| Richmond | | Philadelphia, PA | | 2 | | | | | Oil | | Peaking | | 98 | | |
| Philadelphia Road | | Baltimore, MD | | 4 | | | | | Oil | | Peaking | | 61 | | |
| Eddystone | | Eddystone, PA | | 4 | | | | | Oil | | Peaking | | 60 | | |
| Delaware | | Philadelphia, PA | | 4 | | | | | Oil | | Peaking | | 56 | | |
| Southwark | | Philadelphia, PA | | 4 | | | | | Oil | | Peaking | | 52 | | |
| Falls | | Morrisville, PA | | 3 | | | | | Oil | | Peaking | | 51 | | |
| Moser | | Lower Pottsgrove Twp., PA | | 3 | | | | | Oil | | Peaking | | 51 | | |
| Chester | | Chester, PA | | 3 | | | | | Oil | | Peaking | | 39 | | |
| Schuylkill | | Philadelphia, PA | | 2 | | | | | Oil | | Peaking | | 30 | | |
| Salem | | Lower Alloways
Creek Township, NJ | | 1 | | | 42.59 | | | Oil | | Peaking | | 16 | | (f) |
| Total Mid-Atlantic | | | | | | | | | | | | 9,729 | | |
| | | | | | | | | | | | | |
| ERCOT | | | | | | | | | | | | | |
| Whitetail | | Webb County, TX | | 57 | | | 51 | | (g) | Wind | | Intermittent | | 47 | | (f) |
| Sendero | | Jim Hogg and Zapata County, TX | | 39 | | | 51 | | (g) | Wind | | Intermittent | | 40 | | (f) |
| Constellation Solar Texas | | Various, TX | | 11 | | | | | Solar | | Intermittent | | 13 | | (h) |
| Colorado Bend II | | Wharton, TX | | 3 | | | | | Gas | | Intermediate | | 1,143 | | |
| Wolf Hollow II | | Granbury, TX | | 3 | | | | | Gas | | Intermediate | | 1,115 | | |
| Handley 3 | | Fort Worth, TX | | 1 | | | | | Gas | | Intermediate | | 395 | | |
| Handley 4, 5 | | Fort Worth, TX | | 2 | | | | | Gas | | Peaking | | 870 | | |
| Total ERCOT | | | | | | | | | | | | 3,623 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Station(a) | | Location | | No. of
Units | | Percent Owned(b) | | Primary
Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
| New York | | | | | | | | | | | | | |
| Nine Mile Point | | Scriba, NY | | 2 | | | 50.01 | | (j) | Uranium | | Base-load | | 838 | | (f) |
| FitzPatrick | | Scriba, NY | | 1 | | | | | Uranium | | Base-load | | 842 | | |
| Ginna | | Ontario, NY | | 1 | | | 50.01 | | (j) | Uranium | | Base-load | | 288 | | (f) |
| Solar New York | | Bethlehem, NY | | 1 | | | | | Solar | | Intermittent | | 3 | | (h) |
| Total New York | | | | | | | | | | | | 1,971 | | |
| | | | | | | | | | | | | |
| Other | | | | | | | | | | | | | |
| Antelope Valley | | Lancaster, CA | | 1 | | | | | Solar | | Intermittent | | 242 | | |
| Bluestem | | Beaver County, OK | | 60 | | | 51 | | (g)(k) | Wind | | Intermittent | | 101 | | (f) |
| Shooting Star | | Kiowa County, KS | | 65 | | | 51 | | (g) | Wind | | Intermittent | | 53 | | (f) |
| Albany Green Energy | | Albany, GA | | 1 | | | 99 | | (l) | Biomass | | Base-load | | 50 | | (f) |
| Solar Arizona | | Various, AZ | | 127 | | | | | Solar | | Intermittent | | 46 | | (h) |
| Bluegrass Ridge | | King City, MO | | 27 | | | 51 | | (g) | Wind | | Intermittent | | 29 | | (f) |
| California PV Energy 2 | | Various, CA | | 89 | | | | | Solar | | Intermittent | | 27 | | (h) |
| Conception | | Barnard, MO | | 24 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) |
| Cow Branch | | Rock Port, MO | | 24 | | | 51 | | (g) | Wind | | Intermittent | | 26 | | (f) |
| Solar Arizona 2 | | Various, AZ | | 56 | | | | | Solar | | Intermittent | | 34 | | (h) |
| California PV Energy | | Various, CA | | 53 | | | | | Solar | | Intermittent | | 21 | | (h) |
| Mountain Home | | Glenns Ferry, ID | | 20 | | | 51 | | (g) | Wind | | Intermittent | | 21 | | (f) |
| High Mesa | | Elmore Co., ID | | 19 | | | 51 | | (g) | Wind | | Intermittent | | 20 | | (f) |
| Echo 1 | | Echo, OR | | 21 | | | 50.49 | | (g) | Wind | | Intermittent | | 17 | | (f) |
| Sacramento PV Energy | | Sacramento, CA | | 4 | | | 51 | | (g) | Solar | | Intermittent | | 30 | | (f) |
| Cassia | | Buhl, ID | | 14 | | | 51 | | (g) | Wind | | Intermittent | | 15 | | (f) |
| Wildcat | | Lovington, NM | | 13 | | | 51 | | (g) | Wind | | Intermittent | | 14 | | (f) |
| Echo 2 | | Echo, OR | | 10 | | | 51 | | (g) | Wind | | Intermittent | | 10 | | (f) |
| Solar Georgia 2 | | Various, GA | | 8 | | | | | Solar | | Intermittent | | 10 | | (h) |
| Tuana Springs | | Hagerman, ID | | 8 | | | 51 | | (g) | Wind | | Intermittent | | 9 | | (f) |
| Solar Georgia | | Various, GA | | 10 | | | | | Solar | | Intermittent | | 8 | | (h) |
| Greensburg | | Greensburg, KS | | 10 | | | 51 | | (g) | Wind | | Intermittent | | 6 | | (f) |
| Solar Massachusetts | | Various, MA | | 10 | | | | | Solar | | Intermittent | | 7 | | (h) |
| Outback Solar | | Christmas Valley, OR | | 1 | | | | | Solar | | Intermittent | | 6 | | (h) |
| Echo 3 | | Echo, OR | | 6 | | | 50.49 | | (g) | Wind | | Intermittent | | 5 | | (f) |
| Holyoke Solar | | Various, MA | | 2 | | | | | Solar | | Intermittent | | 5 | | (h) |
| Three Mile Canyon | | Boardman, OR | | 6 | | | 51 | | (g) | Wind | | Intermittent | | 5 | | (f) |
| Loess Hills | | Rock Port, MO | | 4 | | | | | Wind | | Intermittent | | 5 | | |
| California PV Energy 3 | | Various, CA | | 31 | | | | | Solar | | Intermittent | | 8 | | (h) |
| Denver Airport Solar | | Denver, CO | | 1 | | | 51 | | (g) | Solar | | Intermittent | | 4 | | (f) |
| Solar Net Metering | | Uxbridge, MA | | 1 | | | | | Solar | | Intermittent | | 2 | | (h) |
| Solar Connecticut | | Various, CT | | 1 | | | | | Solar | | Intermittent | | 1 | | (h) |
| Mystic 8, 9 | | Charlestown, MA | | 6 | | | | | Gas | | Intermediate | | 1,413 | | (e) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Station(a) | | Location | | No. of
Units | | Percent Owned(b) | | Primary
Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
| Hillabee | | Alexander City,
AL | | 3 | | | | | Gas | | Intermediate | | 753 | | |
| Mystic 7 | | Charlestown, MA | | 1 | | | | | Oil/Gas | | Intermediate | | 512 | | (m) |
| Wyman 4 | | Yarmouth, ME | | 1 | | | 5.9 | | | Oil | | Intermediate | | 35 | | (f) |
| Grand Prairie | | Alberta, Canada | | 1 | | | | | Gas | | Peaking | | 105 | | |
| West Medway | | West Medway, MA | | 3 | | | | | Oil | | Peaking | | 124 | | |
| West Medway II | | West Medway, MA | | 2 | | | | | Oil/Gas | | Peaking | | 192 | | |
| Framingham | | Framingham, MA | | 3 | | | | | Oil | | Peaking | | 31 | | |
| | | | | | | | | | | | | |
| Mystic Jet | | Charlestown, MA | | 1 | | | | | Oil | | Peaking | | 9 | | (m) |
| Total Other | | | | | | | | | | | | 4,037 | | |
| Total | | | | | | | | | | | | 31,271 | | |
__________
(a)All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, and Salem, which are pressurized water reactors.
(b)100%, unless otherwise indicated.
(c)Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are plants with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods.
(d)For nuclear stations, capacity reflects the annual mean rating. Fossil stations and wind and solar facilities reflect a summer rating.
(e)Generation has announced it will permanently cease generation operations at Byron and Dresden nuclear facilities in 2021 and Mystic Unit 8 and 9 in 2024. See Note 7 — Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information.
(f)Net generation capacity is stated at proportionate ownership share.
(g)Reflects the prior sale of 49% of EGRP to a third party. See Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information.
(h)On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation's solar business. The transaction is expected to be completed in the first half of 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.
(i)Generation has deactivated the site and is evaluating for potential return of service or retirement beyond 2021.
(j)Reflects Generation’s interest in CENG, a joint venture with EDF. See ITEM 1. — BUSINESS — Exelon Generation Company, LLC — Nuclear Facilities for additional information.
(k)EGRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets.
(l)Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity.
(m)Generation has plans to retire and cease plant operations in 2021.
The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies, or generating units being temporarily out of service for inspection, maintenance, refueling, repairs, or modifications required by regulatory authorities.
Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding nuclear insurance of generating facilities, see ITEM 1. BUSINESS — Exelon Generation Company, LLC. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in Generation’s consolidated financial condition or results of operations.
The Utility Registrants
The Utility Registrants' electric substations and a portion of their transmission rights are located on property that they own. A significant portion of their electric transmission and distribution facilities are located above or underneath highways, streets, other public places, or property that others own. The Utility Registrants believe that they have satisfactory rights to use those places or property in the form of permits, grants, easements, licenses, and franchise rights; however, they have not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
The Utility Registrants’ high voltage electric transmission lines owned and in service at December 31, 2020 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Voltage | | Circuit Miles | |
| (Volts) | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | |
| 765,000 | | 90 | | — | | — | | — | | — | | — | |
500,000(a) | | — | | 188 | (a) | 216 | | 109 | | 16 | (a) | — | (a) |
| 345,000 | | 2,676 | | — | | — | | — | | — | | — | |
| 230,000 | | — | | 549 | | 358 | | 770 | | 472 | | 274 | |
| 138,000 | | 2,245 | | 135 | | 55 | | 61 | | 586 | | 214 | |
| 115,000 | | — | | — | | 712 | | 25 | | — | | — | |
| 69,000 | | — | | 177 | | — | | — | | 567 | | 667 | |
___________
(a) In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 9 - Jointly Owned Electric Utility Plant - for additional information.
The Utility Registrants' electric distribution system includes the following number of circuit miles of overhead and underground lines:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Circuit Miles | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
| Overhead | | 35,379 | | 12,967 | | 9,179 | | 4,082 | | 6,007 | | 7,393 |
| Underground | | 32,349 | | 9,463 | | 17,650 | | 6,949 | | 6,360 | | 2,984 |
Gas
The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2020:
| | | | | | | | | | | | | | | | | | | | |
| PECO | | BGE | | DPL | |
| Transmission | 9 | | 152 | | 8 | (a) |
| Distribution | 6,946 | | 7,443 | | 2,142 | |
| Service piping | 6,449 | | 6,383 | | 1,461 | |
| Total | 13,404 | | 13,978 | | 3,611 | |
___________
(a) DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities.
The following table presents PECO’s, BGE’s, and DPL’s natural gas facilities:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant | | Facility | | Location | | Storage Capacity
(mmcf) | | Send-out or Peaking Capacity
(mmcf/day) |
| PECO | | LNG Facility | | West Conshohocken, PA | | 1,200 | | 160 |
| PECO | | Propane Air Plant | | Chester, PA | | 105 | | 25 |
| BGE | | LNG Facility | | Baltimore, MD | | 1,056 | | 332 |
| BGE | | Propane Air Plant | | Baltimore, MD | | 550 | | 85 |
| DPL | | LNG Facility | | Wilmington, DE | | 250 | | 25 |
PECO, BGE, and DPL also own 30, 30, and 10 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout their gas service territory, respectively.
First Mortgage and Insurance
The principal properties of ComEd, PECO, PEPCO, DPL, and ACE are subject to the lien of their respective Mortgages under which their respective First Mortgage Bonds are issued. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants maintain property insurance against loss or damage to their properties by fire or other perils, subject to certain exceptions. For their insured losses, the Utility Registrants are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of the Utility Registrants.
Exelon
Security Measures
The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes, and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.
All Registrants
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.
| | | | | |
| ITEM 4. | MINE SAFETY DISCLOSURES |
All Registrants
Not Applicable to the Registrants.
PART II
(Dollars in millions except per share data, unless otherwise noted)
| | | | | |
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Exelon
Exelon’s common stock is listed on the Nasdaq (trading symbol: EXC). As of January 31, 2021, there were 976,337,799 shares of common stock outstanding and approximately 91,240 record holders of common stock.
Stock Performance Graph
The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 2016 through 2020.
This performance chart assumes:
•$100 invested on December 31, 2015 in Exelon common stock, the S&P 500 Stock Index, and the S&P Utility Index; and
•All dividends are reinvested.
| | | | | | | | | | | | | | | | | | | | |
| Value of Investment at December 31, |
| 2015 | 2016 | 2017 | 2018 | 2019 | 2020 |
| Exelon Corporation | $100 | $132.81 | $152.79 | $180.80 | $188.53 | $181.20 |
| S&P 500 | $100 | $111.96 | $136.40 | $130.42 | $171.49 | $203.04 |
| S&P Utilities | $100 | $116.29 | $130.36 | $135.72 | $171.48 | $172.31 |
Generation
As of January 31, 2021, Exelon indirectly held the entire membership interest in Generation.
ComEd
As of January 31, 2021, there were 127,021,370 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 31, 2021, in addition to Exelon, there were 286 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.
PECO
As of January 31, 2021, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon.
BGE
As of January 31, 2021, there were 1,000 outstanding shares of common stock, without par value, of BGE, all of which were indirectly held by Exelon.
PHI
As of January 31, 2021, Exelon indirectly held the entire membership interest in PHI.
Pepco
As of January 31, 2021, there were 100 outstanding shares of common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon.
DPL
As of January 31, 2021, there were 1,000 outstanding shares of common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon.
ACE
As of January 31, 2021, there were 8,546,017 outstanding shares of common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon.
All Registrants
Dividends
Under applicable Federal law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to Exelon.
ComEd has agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its
guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.
Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the DPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.
Exelon’s Board of Directors approved an updated dividend policy for 2021. The 2021 quarterly dividend will remain the same as the 2020 dividend of $0.3825 per share.
At December 31, 2020, Exelon had retained earnings of $16,735 million, including Generation’s undistributed earnings of $2,805 million, ComEd’s retained earnings of $1,456 million consisting of retained earnings appropriated for future dividends of $3,095 million, partially offset by $1,639 million of unappropriated accumulated deficits, PECO’s retained earnings of $1,519 million, BGE’s retained earnings of $1,879 million, and PHI's undistributed losses of $68 million.
The following table sets forth Exelon’s quarterly cash dividends per share paid during 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 |
| (per share) | Fourth
Quarter | | Third
Quarter | | Second
Quarter | | First
Quarter | | Fourth
Quarter | | Third
Quarter | | Second
Quarter | | First
Quarter |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Exelon | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3825 | | | $ | 0.3625 | | | $ | 0.3625 | | | $ | 0.3625 | | | $ | 0.3625 | |
The following table sets forth Generation's and PHI's quarterly distributions and ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's quarterly common dividend payments:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 |
| (in millions) | 4th
Quarter | | 3rd
Quarter | | 2nd
Quarter | | 1st
Quarter | | 4th
Quarter | | 3rd
Quarter | | 2nd
Quarter | | 1st
Quarter |
| Generation | $ | 328 | | | $ | 469 | | | $ | 469 | | | $ | 468 | | | $ | 225 | | | $ | 225 | | | $ | 224 | | | $ | 225 | |
| ComEd | 126 | | | 124 | | | 124 | | | 125 | | | 128 | | | 126 | | | 127 | | | 127 | |
| PECO | 85 | | | 85 | | | 85 | | | 85 | | | 90 | | | 88 | | | 90 | | | 90 | |
| BGE | 60 | | | 62 | | | 62 | | | 62 | | | 55 | | | 57 | | | 56 | | | 56 | |
| PHI | 102 | | | 183 | | | 134 | | | 134 | | | 97 | | | 213 | | | 88 | | | 128 | |
| Pepco | 58 | | | 73 | | | 73 | | | 28 | | | 40 | | | 101 | | | 48 | | | 24 | |
| DPL | 42 | | | 33 | | | 14 | | | 52 | | | 34 | | | 35 | | | 29 | | | 41 | |
| ACE | 3 | | | 76 | | | 12 | | | 23 | | | 24 | | | 76 | | | 12 | | | 12 | |
First Quarter 2021 Dividend
On February 21, 2021, Exelon's Board of Directors declared a regular quarterly dividend of $0.3825 per share on Exelon’s common stock for the first quarter of 2021. The dividend is payable on Monday, March 15, 2021, to shareholders of record of Exelon as of 5 p.m. Eastern time on Monday, March 8, 2021.
| | | | | |
| Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Exelon
Executive Overview
Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
Exelon has eleven reportable segments consisting of Generation’s five reportable segments (Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2020 compared to the year ended December 31, 2019, and is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. For discussion of the year ended December 31, 2019 compared to the year ended December 31, 2018, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2019 Form 10-K, which was filed with the SEC on February 11, 2020.
COVID-19. The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of COVID-19. The Registrants provide a critical service to our customers which means that it is paramount that we keep our employees who operate our businesses safe and minimize unnecessary risk of exposure to the virus. The Registrants have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities. The Registrants have implemented work from home policies where appropriate, and imposed travel limitations on their employees. In addition, the Registrants have updated existing business continuity plans in the context of this pandemic.
The Registrants continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers.
There were no changes in internal control over financial reporting in 2020 as a result of COVID-19 that materially affected, or are reasonably likely to materially affect, any of the Registrants’ internal control over financial reporting. See ITEM 9A. CONTROLS AND PROCEDURES for additional information.
Unfavorable economic conditions due to COVID-19 have impacted the demand for electricity and natural gas at Generation and the Utility Registrants, which has resulted in a decrease in operating revenues.
As a result of COVID-19, Generation temporarily suspended interruption of service for all retail residential customers for non-payment and temporarily ceased new late payment fees for all retail customers from March to May of 2020. Starting in March of 2020, the Utility Registrants also temporarily suspended customer disconnections for non-payment and temporarily ceased new late payment fees for all customers and restored service to customers upon request who were disconnected in the last twelve months. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on such measures at the Utility Registrants. At Generation, such measures resulted in an increase in credit loss expense. ComEd and ACE recorded regulatory assets for the incremental credit loss expense based on existing mechanisms. BGE, PECO, Pepco, and DPL also recorded regulatory assets for substantially all the incremental credit loss expense incurred in 2020. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Generation and the Utility Registrants have also incurred direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of their employees. At Generation and PECO, such costs are recorded as Operating and maintenance expense and are excluded from Adjusted (non-GAAP) Operating Earnings. At ComEd, BGE, Pepco, DPL, and ACE, such costs are primarily recorded as regulatory assets. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The estimated impact to Generation’s and the Utility Registrants’ Net income is approximately $170 million and $75 million for the year ended December 31, 2020, respectively.
To offset the unfavorable impacts from COVID-19, the Registrants identified approximately $250 million in cost savings across Generation and the Utility Registrants in 2020. The cost savings achieved in 2020 were higher than originally anticipated.
The Registrants rely on the capital markets for publicly offered debt as well as the commercial paper markets to meet their financial commitments and short-term liquidity needs. As a result of the disruptions in the commercial paper markets in March of 2020, Generation borrowed $1.5 billion on its revolving credit facility to refinance commercial paper, which Generation repaid on April 3, 2020. Generation also entered into two short-term loan agreements in March of 2020 for an aggregate of $500 million. On April 8, 2020, Generation received approximately $500 million in cash after entering into an accounts receivable financing arrangement. On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility to be used as an additional source of short-term liquidity. In addition, the Registrants issued long-term debt of $5.3 billion and were able to successfully complete their planned long-term debt issuances in 2020. See Liquidity and Capital Resources, Note 17 — Debt and Credit Agreements, and Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants assessed long-lived assets, goodwill, and investments for recoverability and there were no material impairment charges recorded in 2020 as a result of COVID-19. See Note 12 — Asset Impairments for additional information related to other impairment assessments in the third quarter of 2020. Certain assumptions are highly sensitive to changes. Changes in significant assumptions could potentially result in future impairments, which could be material.
This is an evolving situation that could lead to extended disruption of economic activity in our markets. The Registrants will continue to monitor developments affecting their workforce, customers, and suppliers and will take additional precautions that they determine to be necessary in order to mitigate the impacts. The extent to which COVID-19 may impact the Registrants’ ability to operate their generating and transmission and distribution assets, the ability to access capital markets, and results of operations, including demand for electricity and natural gas, will depend on the spread and proliferation of COVID-19 around the world and future developments, which are highly uncertain and cannot be predicted at this time.
Financial Results of Operations
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the year ended December 31, 2020 compared to the same period in 2019. For additional information regarding the financial results for the years ended December 31, 2020and2019 see the discussions of Results of Operations by Registrant.
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | (Unfavorable) Favorable Variance |
| Exelon | $ | 1,963 | | | $ | 2,936 | | | $ | (973) | |
| Generation | 589 | | | 1,125 | | | (536) | |
| ComEd | 438 | | | 688 | | | (250) | |
| PECO | 447 | | | 528 | | | (81) | |
| BGE | 349 | | | 360 | | | (11) | |
| PHI | 495 | | | 477 | | | 18 | |
| Pepco | 266 | | | 243 | | | 23 | |
| DPL | 125 | | | 147 | | | (22) | |
| ACE | 112 | | | 99 | | | 13 | |
Other(a) | (355) | | | (242) | | | (113) | |
__________
(a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income attributable to common shareholdersdecreased by $973 million and diluted earnings per average common share decreased to $2.01 in 2020 from $3.01 in 2019 primarily due to:
•One-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024, partially offset by the absence of accelerated depreciation and amortization due to the early retirement of TMI in September 2019;
•Impairment of the New England asset group;
•Payments that ComEd made under the Deferred Prosecution Agreement. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information;
•Lower capacity revenue;
•Reduction in load due to COVID-19 at Generation;
•Lower realized energy prices;
•Higher nuclear outage days;
•Impact of Generation's annual update to the nuclear ARO for Non-Regulatory Agreement Units;
•Lower net unrealized and realized gains on NDT funds;
•COVID-19 direct costs;
•Lower electric distribution earnings from lower allowed ROE due to a decrease in treasury rates, partially offset by higher rate base at ComEd;
•Higher storm costs related to the June 2020 and August 2020 storms at PECO, net of tax repairs, and related to the August 2020 storm at DPL;
•Unfavorable weather conditions at PECO, DPL Delaware, and ACE; and
•A net increase in depreciation and amortization expense due to ongoing capital expenditures at PECO, BGE, Pepco, DPL, and ACE, partially offset at Generation due to the impact of environmental regulation.extending the operating license at Peach Bottom.
The decreases were partially offset by;
•Higher mark-to-market gains;
•Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter and were fair valued based on quoted market prices of the stocks as of December 31, 2020;
•Lower operating and maintenance expense at Generation primarily due to previous cost management programs, lower contracting costs, and lower travel costs, partially offset by lower NEIL insurance distributions;
•Lower nuclear fuel costs;
•A tax benefit related to a settlement in the first quarter of 2020, partially offset by the absence of a tax benefit related to certain research and development activities recorded in the fourth quarter of 2019 at Generation;and
•Regulatory rate increases at BGE, DPL, and ACE.
Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
The following table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2020 as compared to 2019:
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| 2020 | | 2019 |
| (All amounts in millions after tax) | | | Earnings per
Diluted Share | | | | Earnings per
Diluted Share |
| Net Income Attributable to Common Shareholders | $ | 1,963 | | | $ | 2.01 | | | $ | 2,936 | | | $ | 3.01 | |
| Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $73 and $66, respectively) | (213) | | | (0.22) | | | 197 | | | 0.20 | |
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $278 and $269, respectively)(a) | (256) | | | (0.26) | | | (299) | | | (0.31) | |
| | | | | | | |
Asset Impairments (net of taxes of $135 and $56, respectively)(b) | 396 | | | 0.41 | | | 123 | | | 0.13 | |
Plant Retirements and Divestitures (net of taxes of $244 and $9, respectively)(c) | 718 | | | 0.74 | | | 118 | | | 0.12 | |
Cost Management Program (net of taxes of $14 and $17, respectively)(d) | 45 | | | 0.05 | | | 51 | | | 0.05 | |
| Litigation Settlement Gain (net of taxes of $7) | — | | | — | | | (19) | | | (0.02) | |
Asset Retirement Obligation (net of taxes of $16 and $9, respectively)(e) | 48 | | | 0.05 | | | (84) | | | (0.09) | |
| Change in Environmental Liabilities (net of taxes of $6 and $8, respectively) | 18 | | | 0.02 | | | 20 | | | 0.02 | |
COVID-19 Direct Costs (net of taxes of $19)(f) | 50 | | | 0.05 | | | — | | | — | |
Deferred Prosecution Agreement Payments (net of taxes of $0)(g) | 200 | | | 0.20 | | | — | | | — | |
Acquisition Related Costs (net of taxes of $1)(h) | 4 | | | — | | | — | | | — | |
ERP System Implementation Costs (net of taxes of $1)(i) | 3 | | | — | | | — | | | — | |
Income Tax-Related Adjustments (entire amount represents tax expense)(j) | 71 | | | 0.07 | | | 5 | | | 0.01 | |
Noncontrolling Interests (net of taxes of $19 and $26, respectively)(k) | 103 | | | 0.11 | | | 90 | | | 0.09 | |
| Adjusted (non-GAAP) Operating Earnings | $ | 3,149 | | | $ | 3.22 | | | $ | 3,139 | | | $ | 3.22 | |
__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT funds, the marginal statutory income tax rates for 2020 and 2019 ranged from 26.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT funds were 52.1% and 47.3% for the years ended December 31, 2020 and 2019, respectively.
(a)Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.
(b)In 2020, reflects an impairment at ComEd in the second quarter of 2020 related to the acquisition of transmission assets and an impairment of the New England asset group in the third quarter of 2020. In 2019, primarily reflects the impairment of equity method investments in certain distributed energy companies. The impact of such impairment net of noncontrolling interest is $0.02.
(c)In 2020, primarily reflects one-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024. In 2019, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility and certain fossil sites and the loss on the sale of Oyster Creek to Holtec, partially offset by net realized gains related to Oyster Creek's NDT fund investments, a net benefit associated with remeasurements of the TMI ARO, and a gain on the sale of certain wind assets.
(d)Primarily represents reorganization and severance costs related to cost management programs.
(e)Reflects an adjustment to Generation's nuclear ARO for Non-Regulatory Agreement Units resulting from the annual update.
(f)Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(g)Reflects the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered into on July 17, 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.
(h)Reflects costs related to the acquisition of EDF's interest in CENG.
(i)Reflects costs related to a multi-year ERP system implementation.
(j)Primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.
(k)Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items. In 2020, primarily related to unrealized gains and losses on NDT fund investments for CENG units. In 2019, primarily related to the impact of unrealized gains on NDT fund investments and the impact of the Generation's annual nuclear ARO update for CENG units, partially offset by the impairment of certain equity investments in distributed energy companies.
Significant 2020 Transactions and Developments
Planned Separation
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Impacts of February 2021 Weather Events and Texas-based Generating Assets Outages
Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced periodic outages as a result of historically severe cold weather conditions. In addition, those weather conditions drove increased demand for service, limited the availability of natural gas to fuel power plants, and dramatically increased wholesale power and gas prices.
Exelon and Generation estimate the impact to their Net income for the first quarter of 2021 arising from these market and weather conditions to be approximately $560 million to $710 million. The estimated impact includes favorable results in certain regions within Generation’s wholesale gas business. The ultimate impact to Exelon’s and Generation’s consolidated financial statements may be affected by a number of factors, including final settlement data, the impacts of customer and counterparty credit losses, any state sponsored solutions to address the financial challenges caused by the event, and litigation and contract disputes which may result. Exelon expects to offset between $410 million and $490 million of this impact primarily at Generation through a combination of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings.
See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Agreement for Sale of Generation’s Solar Business
On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation’s solar business, including 360 megawatts of generation in operation or under construction across more than 600 sites across the United States, for a purchase price of $810 million. Completion of the transaction is expected to occur in the first half of 2021. Generation will retain certain solar assets not included in this agreement, primarily Antelope Valley. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Early Retirement of Generation Facilities
In August 2020, Generation announced that it intends to retire the Byron Generating Station in September 2021, Dresden Generating Station in November 2021, and Mystic Units 8 and 9 at the expiration of the cost of service commitment in May 2024. As a result, in the third quarter of 2020, Exelon and Generation recognized a $500 million impairment of its New England asset group and one-time non-cash charges for Byron, Dresden, and Mystic related to materials and supplies inventory reserve adjustments, employee-related costs, and construction work-in-progress impairments, among other items. In addition, there will be ongoing annual financial impacts stemming from shortening the expected economic useful lives of these facilities, primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel. Such ongoing charges are excluded from Adjusted (non-GAAP) Operating Earnings.
The following table summarizes the incremental expense recorded for the year ended December 31, 2020 and the estimated amounts of incremental expense expected to be incurred through the retirement dates.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Actual | | Projected(a) |
| Income statement expense (pre-tax) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| Depreciation and amortization | | | | | | | | | |
Accelerated depreciation(b) | $ | 921 | | | $ | 2,070 | | | $ | 110 | | | $ | 120 | | | $ | 50 | |
| Accelerated nuclear fuel amortization | 60 | | | 170 | | | — | | | — | | | — | |
| Operating and maintenance | | | | | | | | | |
| One-time charges | 277 | | | 30 | | | 10 | | | — | | | 20 | |
Other charges(c) | 35 | | | 10 | | | 10 | | | 10 | | | 5 | |
| | | | | | | | | |
Contractual offset(d) | (364) | | | (475) | | | — | | | — | | | — | |
| Total | $ | 929 | | | $ | 1,805 | | | $ | 130 | | | $ | 130 | | | $ | 75 | |
| | | | | | | | | |
_________
(a)Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.
(b)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(c)Reflects primarily the net impacts associated with the remeasurement of the ARO for Dresden. See Note 10 – Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
(d)Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of the ARO for Byron and Dresden. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activities result in a regulatory liability at ComEd. Recognition of a regulatory asset for nuclear decommissioning-related activities at ComEd is not permissible. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 10 – Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
Deferred Prosecution Agreement
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into ComEd’s lobbying activities in the State of Illinois. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the United States Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date. The payments will not be recovered in rates or charged to customers, and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. See Note 19 — Commitments and Contingencies for additional information.
Utility Distribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2020. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement (Decrease) Increase | | Approved Revenue Requirement (Decrease) Increase | | Approved ROE | | Approval Date | | Rate Effective Date |
| ComEd - Illinois | | April 8, 2019 | | Electric | | $ | (6) | | | $ | (17) | | | 8.91 | % | | December 4, 2019 | | January 1, 2020 |
| ComEd - Illinois | | April 16, 2020 | | Electric | | (11) | | | (14) | | | 8.38 | % | | December 9, 2020 | | January 1, 2021 |
| BGE - Maryland | | May 15, 2020 (amended September 11, 2020) | | Electric | | 137 | | | 81 | | | 9.50 | % | | December 16, 2020 | | January 1, 2021 |
| | Natural Gas | | 91 | | | 21 | | | 9.65 | % | | |
| DPL - Maryland | | December 5, 2019 (amended April 23, 2020) | | Electric | | 17 | | | 12 | | | 9.60 | % | | July 14, 2020 | | July 16, 2020 |
| DPL - Delaware | | February 21, 2020 (amended October 9, 2020) | | Natural Gas | | 7 | | | 2 | | | 9.60 | % | | January 6, 2021 | | September 21, 2020 |
Pending Distribution Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing |
| PECO - Pennsylvania | | September 30, 2020 | | Natural Gas | | $ | 69 | | | 10.95 | % | | Second quarter of 2021 |
| Pepco - District of Columbia | | May 30, 2019 (amended June 1, 2020) | | Electric | | 136 | | | 9.7 | % | | Second quarter of 2021 |
| Pepco - Maryland | | October 26, 2020 | | Electric | | 110 | | | 10.2 | % | | Second quarter of 2021 |
| DPL - Delaware | | March 6, 2020 (amended February 2, 2021) | | Electric | | 23 | | | 10.3 | % | | Third quarter of 2021 |
| ACE - New Jersey | | December 9, 2020 | | Electric | | 67 | | | 10.3 | % | | Fourth quarter of 2021 |
Transmission Formula Rates
The following total increases/(decreases) were included in the Utility Registrants' 2020 annual electric transmission formula rate updates. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant | | Initial Revenue Requirement Increase/(Decrease) | | Annual Reconciliation Decrease | | Total Revenue Requirement Increase/(Decrease) | | Allowed Return on Rate Base | | Allowed ROE |
| ComEd | | $ | 18 | | | $ | (4) | | | $ | 14 | | | 8.17 | % | | 11.50 | % |
| PECO | | 5 | | | (28) | | | (23) | | | 7.47 | % | | 10.35 | % |
| BGE | | 16 | | | (3) | | | 4 | | | 7.26 | % | | 10.50 | % |
| Pepco | | 2 | | | (46) | | | (44) | | | 7.81 | % | | 10.50 | % |
| DPL | | (4) | | | (40) | | | (44) | | | 7.20 | % | | 10.50 | % |
| ACE | | 5 | | | (25) | | | (20) | | | 7.40 | % | | 10.50 | % |
Sales of Customer Accounts Receivable
On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by Generation, entered into an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain customer accounts receivables. Generation received approximately $500 million of cash in accordance with the initial sale of approximately $1.2 billion receivables. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
Exelon’s Strategy and Outlook
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
In 2021, the businesses remain focused on maintaining industry leading operational excellence, meeting or exceeding their financial commitments, ensuring timely recovery on investments to enable customer benefits, supporting enactment of clean energy policies, and continued commitment to corporate responsibility.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest
reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean, and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and match supply to customers. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS for additional information regarding market and financial factors.
Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses. The Utility Registrants anticipate investing approximately $27 billion over the next four years in electric and natural gas infrastructure improvements and modernization projects, including smart grid technology, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $15 billion by the end of 2024. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.
Competitive Energy Businesses. Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that match supply to customers as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development.
Other Key Business Drivers and Management Strategies
Utility Rates and Rate Proceedings
The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows, and financial positions. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings.
Power Markets
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly
over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
Section 232 Uranium Petition
On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce ("DOC") seeking relief under Section 232 of the Trade Expansion Act of 1962 from imports of uranium products, alleging that these imports threaten national security.
The United States Nuclear Fuel Working Group ("Working Group") report was made public on April 23, 2020. The Working Group report states that nuclear power is intrinsically tied to national security, and promises that the U.S. government will take bold actions to strengthen all parts of the nuclear fuel industry in the U.S. It recommends the Agreement Suspending the Antidumping Investigation on Uranium from the Russian Federation (the “Russian Suspension Agreement” or "RSA") be extended and to consider reducing the amount of Russian imports of nuclear fuel. The Russian Suspension Agreement is the historical resolution of a 1991 DOC investigation that found that the Russians had been selling or “dumping” cheap uranium products into the U.S. The RSA has been amended several times in the intervening years to allow Russia to supply limited amounts of uranium products into the U.S. It was set to expire at the end of 2020, but was amended on October 5, 2020 to extend for another 20 years.
The Working Group report should be viewed as policy recommendations that may be implemented by executive agencies, congress, and or regulatory bodies. Exelon and Generation cannot currently predict the outcome of all of the policy changes recommended by the Working Group.
Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps
On February 21, 2019, PJM's Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used to calculate the default offer cap for bids to supply capacity in PJM is too high, resulting in an overstated default offer cap that obviates the need for most sellers to seek unit-specific approval of their offers. The IMM claims that this allows for the exercise of market power. The IMM asks FERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. It is too early to predict the final outcome of this proceeding or its potential financial impact, if any, on Exelon or Generation.
Energy Demand
Load growth at the Utility Registrants is driven by recovery from COVID-19 impacts. ComEd and PECO are projecting modest growth in load of 2.5% and 1.8%, respectively, in 2021 as compared to reduced load in 2020. BGE, Pepco, DPL, and ACE are projecting slower growth as prolonged COVID-19 impacts decrease load by (2.0)%, (0.8)%, (0.9)%, and (2.4)%, respectively, in 2021 compared to 2020.
Retail Competition
Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. Forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.
Hedging Strategy
Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. As of December 31, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% for 2021. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk.
Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 60% of Generation’s uranium concentrate requirements from 2021 through 2025 are supplied by three suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s consolidated financial statements.
See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Other Legislative and Regulatory Developments
Delaware Distribution System Investment ChargeIllinois Clean Energy Progress Act
On JuneMarch 14, 2018,2019, the GovernorClean Energy Progress Act was introduced in the Illinois General Assembly to preserve Illinois’ clean energy choices arising from FEJA and empower the IPA to conduct capacity procurements outside of Delaware signedPJM’s base residual auction process, while utilizing the FRR provisions in PJM's tariffs which are still subject to penalties and other obligations under the PJM tariffs. The most significant provisions of the proposed legislation are as follows: (1) it allows the IPA to procure capacity directly from clean energy resources that have previously sold ZECs or RECs, including certain of Generation’s nuclear plants in Illinois, or from new Distribution System Investment Charge (DSIC) legislation, whichclean energy resources, (2) it establishes a system improvement charge that provides a mechanismgoal of achieving 100% carbon-free power in the ComEd service territory by 2032, and (3) it implements reforms to recover infrastructure investments, allowing for gradual rate increasesenhance consumer protections in the state’s competitive retail electricity and limiting frequencynatural gas markets, including Generation’s retail customers. Energy legislation has also been proposed by other stakeholders in 2019 and 2020, including renewable resource developers, environmental advocates, and coal-fueled generators. Lawmakers focused their efforts on understanding all of distribution base rate cases. On November 30, 2018, DPL filed its first electric and gas filing in Delawarethe various legislative proposals with the new rates being put into effectgoal of developing a single comprehensive energy package for ultimate consideration by the General Assembly and Governor Pritzker. Due to the COVID-19 pandemic, the legislative calendar during 2020 was severely curtailed stalling progress on January 1, 2019. Thiscomprehensive energy legislation. The fall 2020 veto session was cancelled. The next opportunity for the General Assembly to consider development of comprehensive energy legislation supports needed infrastructure investment and allows for more timely recovery of those investments, however Exelon, PHI and DPL do not expect a material impact onappears to come during the financial statements.
Pennsylvania Alternative Ratemaking
On June 28, 2018, the Governor of Pennsylvania signed Act 58 of 2018, which authorizes the PAPUC to review and approve utility-proposed alternative rate mechanisms, including options such as decoupling mechanisms, formula rates, multi-year rate plans, and performance based rates.2021 spring legislative session. Exelon and PECOGeneration will work with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or PECO.Generation.
DistrictNuclear Powers Act of Columbia Clean Energy Bill2019
On December 18, 2018,April 12, 2019, the Council of the District of Columbia passed the Clean Energy District of Columbia Omnibus AmendmentNuclear Powers America Act of 2018 (the Act),2019 was introduced to the United States Congress, which was subsequently signed byexpands the Mayorcurrent investment tax credit to existing nuclear power plants. The proposed legislation would provide a credit equal to 30% of continued capital investment in certain nuclear energy-related expenditures, including capital expenses and nuclear fuel, starting from tax years 2019 through 2023. Thereafter, the District of Columbia on January 18, 2019. The Act is expectedcredit rate would be reduced to take effect26% in February 2019 following2024, 22% in 2025, and 10% in 2026 and beyond. To qualify for the expiration of a 30-day review process bycredit, the U.S. House of Representatives. Among other things, the Act would increase electric load by requiring all public buses, taxisplant must be currently operational and other specified fleets to be solely zero-emissions vehicles by 2045. The Act would also clarify that, under certain circumstances, the gasmust have applied for an operating license renewal before 2026. Exelon and electric utilities may offerGeneration are working with legislators and receive cost recovery including a return on investment on capitalstakeholders and related costs for energy efficiency programs in the District of Columbia.
Employees
In January 2017, an election was held at BGE which resulted in union representation for approximately 1,284 employees. BGE and IBEW Local 410 are negotiating an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. Negotiations have been productive and continue. No agreement has been finalized to date and management cannot predict the outcome of such negotiations. Negotiations that began in 2017 for a first collective bargaining agreement with a small unit of employees represented by Local 501 of Operating Engineers at Exelon’s Hyperion Solutions facility are complete andor the new CBA will expire in 2021. During 2017, Generation finalized CBAs with the Security Officer unions at LaSalle, Limerick and Quad Cities, which all will expire in 2020 and Dresden expiring in 2021. Additionally, during 2017, Generation acquired and combined two CBAs at Fitzpatrick into one CBA covering both craft and security employees, which will expire in 2023. Generation also successfully finalized the CBA with the IBEW union at TMI, which will expire in 2022. During 2018, Generation finalized its CBA with the Security Officer’s union at Braidwood, which will expire in 2021. Additionally, ACE successfully finalized two contract renewals with the IBEW Local 210, and the new BAs will expire in 2023. As previously reported, there was an organizing effort over approximately 18 ACE control room System Operators. While an election was held with an outcome favorable to Local 210, collective bargaining over this small segment of employees will not commence until the issue of whether the System Operators are NLRA statutory supervisors is determined, and that matter is currently before the NLRB. Furthermore, there was an organizing effort at PECO over approximately 150 Working Foreperson positions. In October 2018, the Working Foreperson group overwhelmingly rejected unionization in an election held by the NLRB. Lastly,potential financial impact, if any, on December 27, 2018 a representation petition was filed by the LEOSU Union seeking to represent security officers at Clinton Power station who are currently represented by SEIU Local 1. The current collective bargaining agreement between Exelon Nuclear Security and the SEIU Local 1 has been extended, so that the matter between the two rival labor organizations can be resolved. No election or determination has been held and it is anticipated that this matter will be resolved in 2019.Generation.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the accounting policies described below require significant judgment in their application, or incorporate estimates and assumptions that are inherently
uncertain and that may change in subsequent periods. Additional information of the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.
Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)
Generation’s ARO associated with decommissioning its nuclear unitsunits was $10.0$11.9 billion at December 31, 2018.2020. The authoritative guidance requires that Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation uses an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning outcome scenarios.
As a result of recent nuclear plant retirements in the industry, nuclear operators and third-party service providers are obtaining more information about costs associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in changes to existing decommissioning requirements. In addition, as more nuclear plants are retired, it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs. The availability of NDT funds could impact the timing of the decommissioning activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear plant could impact the timing of plant retirements. These factors could result in material changes to Generation’s current estimates as more information becomes available and could change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios.
The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions:
Decommissioning Cost Studies. Generation uses unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless circumstances warrant more frequent updates. As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle.
Cost Escalation Factors. Generation uses cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine escalation factors, and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal, and other costs. All of the nuclear AROs are adjusted each year for the updated cost escalation factors.
Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various scenarios for decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. The assumed decommissioning scenarios include the following three alternatives: (1) DECON which assumes decommissioning activities begin shortly after the cessation of operation, (2) Shortened SAFSTOR generally has a 30-year delay prior to onset of decommissioning activities, and (3) SAFSTOR which assumes the nuclear facility is placed and maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated generally within 60 years after cessation of operations. In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.
The actual decommissioning approach selected once a nuclear facility is shutdown will be determined by Generation at the time of shutdown and may be influenced by multiple factors including the funding status of the nuclear decommissioning trustNDT fund at the time of shutdown.
The assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original 40-year nuclear license term, (2) the probability of operating through an extended
60-year nuclear license term (regardless of whether such 20-year license extension has been received for each unit), (3) the probability of a second, 20-year license renewal for some nuclear units, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory environments. The successful operation of nuclear plants in the U.S. beyond the initial 40-year license terms has prompted the NRC to consider regulatory and technical requirements for potential plant operations for an 80-year nuclear operating term. As power market and regulatory environment developments occur, Generation evaluates and incorporates, as necessary, the impacts of such developments into its nuclear ARO assumptions and estimates.
Generation’s probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal. Generation currently assumes DOE will begin accepting SNF in 2030.2035. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location
and develop the necessary infrastructure for long-term SNF storage. For additional information regarding the estimated date thatwhen DOE will begin accepting SNF, see Note 2219 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
Discount Rates. The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using credit-adjusted, risk-free rates (CARFR) applicable to the various businesses in which each of the nuclear units originally operated. Generation initially recognizes an ARO at fair value and subsequently adjusts it for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions. The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the ARO as a result of upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO. Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, is measured using the average historical CARFR rates used in creating the initial ARO cost layers. If Generation’s future nominal cash flows associated with the ARO were to be discounted at current prevailing CARFR, the obligation would increase from approximately $10.0$11.9 billion to approximately $10.1 billion.$15.0 billion.
The following table illustrates the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO (dollars in millions):
| | | | | |
| Change in the CARFR applied to the annual ARO update | (Decrease) Increase to ARO at December 31, 2020 |
| 2019 CARFR rather than the 2020 CARFR | $ | (370) | |
| 2020 CARFR increased by 50 basis points | (390) | |
| 2020 CARFR decreased by 50 basis points | 490 | |
|
| | | |
| Change in the CARFR applied to the annual ARO update | Increase (Decrease) to ARO at
December 31, 2018 |
| 2017 CARFR rather than the 2018 CARFR | $ | 50 |
|
| 2018 CARFR increased by 50 basis points | (100 | ) |
| 2018 CARFR decreased by 50 basis points | 130 |
|
ARO Sensitivities. Changes in the assumptions underlying the ARO could materially affect the decommissioning obligation. The impact to the ARO of a change in any one of these assumptions is highly dependent on how the other assumptions may correspondingly change.
The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant (dollars in millions):
|
| | | |
| Change in ARO Assumption | Increase to ARO at
December 31, 2018 |
| Cost escalation studies | |
| Uniform increase in escalation rates of 50 basis points | $ | 1,530 |
|
| Probabilistic cash flow models | |
| Increase the estimated costs to decommission the nuclear plants by 10 percent | 650 |
|
Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent(a) | 410 |
|
Shorten each unit's probability weighted operating life assumption by 10 percent(b) | 720 |
|
| Extend the estimated date for DOE acceptance of SNF to 2035 | 90 |
|
__________
| | | | | |
(a)Change in ARO Assumption | Excludes any sites in which management has committedIncrease to a specific decommissioning approach.ARO at December 31, 2020 |
| Cost escalation studies | |
(b)Uniform increase in escalation rates of 50 basis points | Excludes any retired site or sites$ | 2,560 | |
| Probabilistic cash flow models | |
| Increase the estimated costs to decommission the nuclear plants by 10 percent | 1,050 | |
Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent(a) | 610 | |
Shorten each unit's probability weighted operating life assumption by 10 percent(b) | 1,690 | |
Extend the estimated date for which an early plant retirement has been announced.DOE acceptance of SNF to 2040 | 280 | |
__________
(a)Excludes any sites in which management has committed to a specific decommissioning approach.
(b)Excludes any retired sites.
See Note 1 — Significant Accounting Policies, Note 87 — Early Plant Retirements and Note 1510 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for nuclear decommissioning obligations.AROs.
Goodwill (Exelon, ComEd, and PHI)
As of December 31, 2018,2020, Exelon’s $6.7 billion carrying amount of goodwill consists primarily of $2.6 billion at ComEd and $4 billion at PHI and immaterial amounts at Generation and DPL.PHI. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances
change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is testedassessed for impairment. ComEd has a single operating segment and reporting unit. PHI’s operating segments and reporting units are Pepco, DPL, and ACE. See Note��24Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information. Exelon's and ComEd’s goodwill has been assigned entirely to the ComEd reporting unit. Exelon's and PHI’s goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively. See Note 1013 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed.
Exelon’s, ComEd’s and PHI’s accounting policy is to perform a quantitative test of goodwill at least once every three years, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.
Application of the goodwill impairment testassessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, and projected operating and capital cash flows for ComEd’s, Pepco's, DPL's, and ACE's businesses and the fair value of debt. In applying the second step (if needed), management must estimate the fair value of specific assets and liabilities of the reporting unit.
While the 2020 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's, or PHI’s goodwill, which could be material. Based on the results of the last annual quantitative goodwill tests performed as of November 1, 2016 and November 1, 2018 for ComEd and PHI, respectively, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 30%, 20% and 30%, respectively, for ComEd and PHI to fail the first step of their respective impairment tests.
See Note 1 — Significant Accounting Policies and Note 1013 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Purchase Accounting (Exelon, Generation and PHI)
Assets acquired and liabilities assumed in an acquired business are recorded at their estimated fair values on the date of acquisition. The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, often utilizes independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, could significantly impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. The allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed. If the transaction is determined to be an asset acquisition the purchase price is allocated to the assets acquired and the liabilities assumed and no goodwill or bargain purchase gain would be recorded. See Note 5 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Unamortized Energy Contract Assets and Liabilities (Exelon, Generation, and PHI)
Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts that Generation has acquired and the electricity contracts Exelon has acquired as part of the PHI merger. The initial amount recorded represents the fair value of the contracts at the time of acquisition. At Exelon and PHI, offsetting regulatory assets or liabilities were also recorded for those energy contract costs that are probable of recovery or refund through customer rates. The unamortized energy contract assets and liabilities and any corresponding regulatory assets or liabilities, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract assets and liabilities is recorded through purchased power and fuel expense or operating revenues, depending on the nature of the underlying contract. See Note 43 — Regulatory Matters Note 5 — Mergers, Acquisitions and Dispositions and Note 1013 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Impairment of Long-livedLong-Lived Assets (All Registrants)
All Registrants regularly monitor and evaluate theirthe carrying value of long-lived assets and asset groups excluding goodwill, for impairment whenrecoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of potential impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, an asset remaining idle for more than a short period of time, specific regulatory disallowance, advances in technology, plans to dispose of a long-lived asset
significantly before the end of its useful life, and financial distress of a third party for assets contracted with them on a long-term basis, among others.
The review of long-lived assets and asset groups for impairment utilizes significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could have a significant impactpotentially result in the consolidated financial statements.material future impairments. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. For the generation business, the lowest level of independent cash flows is determined by the evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those units as well as the associated intangible assets or liabilities recorded on the balance sheet. The cash flows from the generating units are generally evaluated at a regional portfolio level with cash flows generated from the customer supply and risk management activities, including cash flows from related intangible assets and liabilities on the balance sheet. In certain cases, generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generating assets (typically contracted renewables). For such assets the financial viability of the third party, including the impact of bankruptcy on the contract, may be a significant assumption in the assessment.
On a quarterly basis, Generation assesses its long-lived assets or asset groups for indicators of impairment. If indicators are present for a long-lived asset or asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. When the undiscounted cash flow analysis indicates the carrying value of a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value of the long-lived asset or asset group is dependent upon a market participant’s view of the exit price of the assets. This includes significant assumptions of the estimated future cash flows generated by the assets and market discount rates. Events and circumstances often do not occur as expected and there will usually beresulting in differences between prospective financial information and actual results, and those differenceswhich may be material. The determination of fair value is driven by both internal assumptions that include significant unobservable inputs (Level 3) such as revenue and generation forecasts, projected capital, and maintenance expenditures and discount rates, as well as information from various public, financial and industry sources.
See Note 712 — Impairment of Long-Lived Assets and IntangiblesAsset Impairments of the Combined Notes to Consolidated Financial Statements for a discussion of asset impairment evaluations made by Exelon.assessments.
Depreciable Lives of Property, Plant, and Equipment (All Registrants)
The Registrants have significant investments in electric generation assets and electric and natural gas transmission and distribution assets. These assets are generally depreciated on a straight-line basis, using the group, composite, or unitary methods of depreciation. The group approach is typically for groups of similar assets that have
approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are generally completed every five years, or more frequently if required by a rate regulator or if an event, regulatory action, or change in retirement patterns indicate an update is necessary.
For the Utility Registrants, depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the Utility Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in customer rates, unless the depreciation rates reflected in customer rates do not align with management’s judgment as to an appropriate estimated useful life or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL, and ACE includesinclude an estimate of the future costs of dismantling and removing plant from service upon retirement. See Note 4 -3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for information regarding regulatory liabilities and assets recorded by ComEd, BGE, Pepco, DPL, and ACE related to removal costs.
PECO’s removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. Estimates for such removal costs are also evaluated in the periodic depreciation studies.
At Generation, along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated service lives of its generating facilities.facilities and reassesses the reasonableness of estimated useful lives whenever events or changes in circumstances warrant. When a determination has been made that an asset will be retired before the end of its current estimated useful life, depreciation provisions will be accelerated to reflect the shortened estimated useful life, which could have a material unfavorable impact on Exelon’s and Generation’s future results of operations. See Note 87 — Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information.
Changes in estimated useful lives of electric generation assets and of electric and natural gas transmission and distribution assets could have a significant impact on the Registrants’ future results of operations. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant, and equipment of the Registrants.
Defined Benefit Pension and Other Postretirement Employee Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and other postretirement employee benefitOPEB plans for substantially all current employees. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate, applied to benefit obligations, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon’s expected level ofExelon's contributions, to the plans, the incidence of participant mortality, the expected remaining service period of plan participants, the level of compensation and rate of compensation increases, employee age, length of service, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations. Exelon amortizes actuarial gains or losses in excess of a corridor of 10% of the greater of the projected benefit obligation or the market-related value (MRV) of plan assets over the expected average remaining service period of plan participants.
Pension and other postretirement benefitOPEB plan assets include equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as real estate, private equity, and hedge funds.
Expected Rate of Return on Plan Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations. Exelon calculates the amount of expected return on pension and other postretirement benefitOPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated
value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For other postretirement benefitOPEB plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV.
Discount Rate. At December 31, 2018 and 2017, theThe discount rates wereare determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and other postretirement benefitOPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and other postretirement benefitOPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates.
Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon’s mortality assumption is supported by an actuarial experience study of Exelon's plan participants and utilizes the IRS's RP-2000SOA 2019 base table (Pri-2012) and the Scale BB 2-DimensionalMP-2020 improvement scale with long-term improvementsadjusted to use Proxy SSA ultimate improvement rates.
Sensitivity to Changes in Key Assumptions. The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above, while holding all other assumptions constant (dollars in millions):
|
| | | | | | | | | | | | | | | | | |
| | Actual Assumption | | | | | | | | |
| Actuarial Assumption | Pension | | OPEB | | Change in Assumption | | Pension | | OPEB | | Total |
| Change in 2018 cost: | | | | | | | | | | | |
Discount rate (a) | 3.62% | | 3.61% | | 0.5% | | $ | (51 | ) | | $ | (17 | ) | | $ | (68 | ) |
| | 3.62% | | 3.61% | | (0.5)% | | 62 |
| | 21 |
| | 83 |
|
| EROA | 7.00% | | 6.60% | | 0.5% | | (90 | ) | | (13 | ) | | (103 | ) |
| | 7.00% | | 6.60% | | (0.5)% | | 89 |
| | 13 |
| | 102 |
|
| Change in benefit obligation at December 31, 2018: | | | | | | | | | | | |
Discount rate (a) | 4.31% | | 4.30% | | 0.5% | | (1,180 | ) | | (246 | ) | | (1,426 | ) |
| | 4.31% | | 4.30% | | (0.5)% | | 1,371 |
| | 284 |
| | 1,655 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Actual Assumption | | | | | | | | |
| Actuarial Assumption | Pension | | OPEB | | Change in
Assumption | | Pension | | OPEB | | Total |
| Change in 2020 cost: | | | | | | | | | | | |
Discount rate(a) | 3.34% | | 3.31% | | 0.5% | | $ | (52) | | | $ | (14) | | | $ | (66) | |
| 3.34% | | 3.31% | | (0.5)% | | 70 | | | 15 | | | 85 | |
| EROA | 7.00% | | 6.69% | | 0.5% | | (91) | | | (12) | | | (103) | |
| 7.00% | | 6.69% | | (0.5)% | | 91 | | | 12 | | | 103 | |
| Change in benefit obligation at December 31, 2020: | | | | | | | | | | | |
Discount rate(a) | 2.58% | | 2.51% | | 0.5% | | (1,410) | | | (268) | | | (1,678) | |
| 2.58% | | 2.51% | | (0.5)% | | 1,631 | | | 309 | | | 1,940 | |
__________
| |
(a) | In general, the discount rate will have a larger impact on the pension and other postretirement benefit cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns. |
(a)In general, the discount rate will have a larger impact on the pension and OPEB cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns.
See Note 161 — Significant Accounting Policies and Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and other postretirement benefitOPEB plans.
Regulatory Accounting (Exelon and Utility Registrants)
For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. If it is concluded in a future period that a separable portion of operations no longer meets the criteria discussed above, Exelon and the Utility Registrants would be required to eliminate any associated regulatory assets and liabilities and the impact, which could be material, would be recognized in the Consolidated Statements of Operations and Comprehensive Income and could be material.
Income.
The following table illustrates the gains (losses) that could result from the elimination of regulatory assets and liabilities and charges against OCI (dollars in millions before taxes) related to deferred costs associated with Exelon's pension and other postretirement benefitOPEB plans that are recorded as regulatory assets in Exelon's Consolidated Balance Sheets:
| | | December 31, 2018 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
| December 31, 2020 | | December 31, 2020 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Gain (loss) | $ | 744 |
| | $ | 4,743 |
| | $ | 55 |
| | $ | 694 |
| | $ | (853 | ) | | $ | (84 | ) | | $ | 375 |
| | $ | (6 | ) | Gain (loss) | $ | 79 | | | $ | 4,664 | | | $ | (177) | | | $ | 490 | | | $ | (798) | | | $ | (94) | | | $ | 260 | | | $ | (152) | |
Charge against OCI(a) | $ | 3,754 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Charge against OCI(a) | $ | 3,984 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
___________
| |
(a) | Exelon's charge against OCI (before taxes) consists of up to $2.4 billion, $529 million, $157 million, $413 million, $208 million and $105 million related to ComEd's, BGE's, PHI's, Pepco's, DPL's and ACE's respective portions of the deferred costs associated with Exelon's pension and other postretirement benefit plans. Exelon also has a net regulatory liability of $(47) million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s other postretirement benefit plans that would result in an increase in OCI if reversed. |
(a)Exelon's charge against OCI (before taxes) consists of up to $2.7 billion, $481 million, $193 million, $387 million, $188 million, and $91 million related to ComEd's, BGE's, PHI's, Pepco's, DPL's, and ACE's respective portions of the deferred costs associated with Exelon's pension and OPEB plans. Exelon also has a net regulatory liability of $(36) million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s OPEB plans that would result in an increase in OCI if reversed.
See Note 43 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including the regulatory assets and liabilities tables of Exelon and the Utility Registrants.
For each regulatory jurisdiction in which they conduct business, Exelon and the Utility Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or settlementrefund at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs in each Registrant's jurisdictions, and factors such as changes in applicable regulatory and political environments. If the assessments and estimates made by Exelon and the Utility Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statements could be material.
Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric distribution and energy efficiency formula rates for ComEd, and FERC transmission formula rate tariffs for the Utility Registrants.
Accounting for Derivative Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange risk, and interest rate risk related to ongoing business operations. The Registrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP). See Note 1216 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants account for derivative financial instruments under the applicable authoritative guidance. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlyings and one or more notional quantities. Changes in management’s assessment of contracts and the liquidity of their markets, and changes in authoritative guidance, could result in previously excluded contracts becoming in scope toof new authoritative guidance.
Under current authoritative guidance, allAll derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, the normal purchases and normal sales exception.NPNS. Derivatives entered into for economic hedging and for proprietary trading purposes are recorded at fair value through earnings. For economic hedges that are not designated for hedge accounting for the Utility Registrants, changes in the fair value each period are generally recorded with a corresponding offsetting regulatory asset or liability given likelihood of recovering the associated costs through customer rates.
Normal Purchases and Normal Sales Exception. NPNS. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While some of these contracts are considered derivative financial instruments under the authoritative guidance, certain of these qualifying transactions have been designated by Generation as normal purchases and normal salesNPNS transactions, which are thus not required to be
recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for the normal purchases and normal sales exceptionNPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all of the associated qualification and documentation requirements. Revenues and expenses on contracts that qualify as normal purchases and normal salesNPNS are recognized when the underlying physical transaction is completed. Contracts that qualify for the normal purchases and normal sales exceptionNPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and the contract is not financially settled on a net basis. The contracts that ComEd has entered into with suppliers as part of ComEd’s energy procurement process, PECO’s full requirement contracts under the PAPUC-approved DSP program, most of PECO’s natural gas supply agreements, all of BGE’s full requirement contracts and natural gas supply agreements that are derivatives, and certain Pepco, DPL, and ACE full requirement contracts qualify for and are accounted for under the normal purchases and normal sales exception.NPNS.
Commodity Contracts. Identification of a commodity contract as an economic hedge requires Generation to determine that the contract is in accordance with the RMP. Generation reassesses its economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP.
As a part of the authoritative guidance, the Registrants make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding whether or not to enter into derivative transactions, and in determining the initial accounting treatment for derivative transactions. Under the authoritative guidance for fair value measurements, the Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.
Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy.
Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges. The price quotations reflect the average of the bid-ask mid-point from markets that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. The Registrant’s derivatives are traded predominately at liquid trading points. The remaining derivative contracts are valued using models that consider inputs such as contract terms, including maturity, and market parameters, and assumptions of the future prices of energy, interest rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, the model inputs are generally observable. Such instruments are categorized in Level 2.
For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3.
The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts, including both historical and current market data in its assessment of nonperformance risk, including credit risk. The impacts of nonperformance and credit risk to date have generally not been material to the financial statements.
Interest Rate and Foreign Exchange Derivative Instruments. The Registrants may utilize fixed-to-floating interest rate swaps to achieve the targeted level of variable-rate debt as a percent of total debt. Additionally, the Registrants may use forward-starting interest rate swaps and treasury rate locks to lock in interest-rate levels and floating to fixed swaps for project financing. In addition, Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. Generation does not utilize interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. The fair value of the agreements is calculated by discounting the future net cash flows to the present value based on observable inputs and are primarily categorized in Level 2 in the fair value hierarchy. Certain exchange based interest rate derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 1118 — Fair Value of Financial Assets and Liabilities and Note 1216 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.
Taxation (All Registrants)
Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the Registrants’ consolidated financial statements.
The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and their intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the Registrant's inability to realize its deferred tax assets. Based on the combined assessment, the Registrants record valuation allowances for deferred tax assets when it is more-likely-than-not such benefit will not be realized in future periods.
Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, the Registrants’ forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Accounting for Loss Contingencies (All Registrants)
In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved. Such difference could have a significant impact in the Registrants' consolidated financial statements.
Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work and changes in technology, regulations, and the requirements of local governmental authorities. Annual studies and/or reviews are conducted at ComEd, PECO, BGE, and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. In addition, periodic reviews are performed at each of the Registrants to assess the adequacy of other environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant impact in the Registrants’ consolidated financial statements. See Note 2219 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Other, Including Personal Injury Claims. The Registrants are self-insured for general liability, automotive liability, workers’ compensation, and personal injury claims to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. The Registrants have reserves for both open claims asserted and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact in the Registrants’ consolidated financial statements.
Revenue Recognition (All Registrants)
Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from various business activities including: the sale of power and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets (wholesale and retail); the sale and delivery of power and natural gas in regulated markets; and the provision of other energy-related non-regulated products and services.
The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily apply the Revenue from Contracts with Customers, Derivative and Alternative Revenue Program (ARP)ARP guidance to recognize revenue as discussed in more detail below.
Revenue from Contracts with Customers.Under the Revenue from Contracts with Customers guidance, the The Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power, natural gas, and other energy-related commodities are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as normal purchases and normal sales (NPNS),NPNS, sales to utility customers under regulated service tariffs, and spot-market energy commodity sales, including settlements with independent system operators.ISOs.
The determination of Generation’s and the Utility Registrants' retail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally on a monthly basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the utilities’ customers and favorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of customers electing to use an alternate supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.
Derivative Revenues. The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-market revenues and expenses include: inception gains or losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses.
Alternative Revenue Program Accounting. Certain of the Utility Registrants’ ratemaking mechanisms qualify as Alternative Revenue Programs (ARPs)ARPs if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, which include the Utility Registrants’ formula rate mechanisms and revenue decoupling mechanisms, the Utility Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of “originating” ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the “originating” ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers.
ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, distributed generation rebates, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco, and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates
that they believe are probable of approval by FERC in
accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts.
See Note 43 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Allowance for UncollectibleCredit Losses on Customer Accounts Receivable (Utility Registrants)
Utility Registrants estimate the allowance for uncollectible accountscredit losses on customer receivables by applying loss rates developed specifically for each company based on historical loss experience, current conditions, and forward-looking risk factors to the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar forward-looking credit quality indicators and risk factors that are comprised based on various attributes, including delinquency of their balances and payment history.history and represent expected, future customer behavior. Loss rates applied to the accounts receivable balances are based on a historical average of charge-offs as a percentage of accounts receivable in each risk segment. The Utility Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Utility Registrants' allowances for uncollectible accountscredit losses will continue to be affected by changes in volume, prices, and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DPSC, and NJBPU regulations.
Results of Operations by Registrant
The Registrants'Results of Operations—Generation
Generation’s Results of Operations includes discussion of RNF, which is a financial measure not defined under GAAP and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. The CODMs for Exelon and Generation evaluate the performance of Generation's electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measure because it provides information that can be used to evaluate its operational performance. For the Utility Registrants, their Operating revenues reflect the full and current recovery of commodity procurement costs given the rider mechanisms approved by their respective state regulators. The commodity procurement costs, which are recorded in Purchased power and fuel expense, and the associated revenues can be volatile. Therefore, the Utility Registrants believe that RNF is a useful measure because it excludes the effect on Operating revenues caused by the volatility in these expenses.
| | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | (Unfavorable) Favorable Variance | | | | |
| Operating revenues | $ | 17,603 | | | $ | 18,924 | | | $ | (1,321) | | | | | |
| Purchased power and fuel expense | 9,585 | | | 10,856 | | | 1,271 | | | | | |
Revenues net of purchased power and fuel expense | 8,018 | | | 8,068 | | | (50) | | | | | |
| Other operating expenses | | | | | | | | | |
| Operating and maintenance | 5,168 | | | 4,718 | | | (450) | | | | | |
| Depreciation and amortization | 2,123 | | | 1,535 | | | (588) | | | | | |
| Taxes other than income taxes | 482 | | | 519 | | | 37 | | | | | |
| Total other operating expenses | 7,773 | | | 6,772 | | | (1,001) | | | | | |
| | | | | | | | | |
| Gain on sales of assets and businesses | 11 | | | 27 | | | (16) | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Operating income | 256 | | | 1,323 | | | (1,067) | | | | | |
| Other income and (deductions) | | | | | | | | | |
| Interest expense | (357) | | | (429) | | | 72 | | | | | |
| Other, net | 937 | | | 1,023 | | | (86) | | | | | |
| Total other income and (deductions) | 580 | | | 594 | | | (14) | | | | | |
| Income before income taxes | 836 | | | 1,917 | | | (1,081) | | | | | |
| Income taxes | 249 | | | 516 | | | 267 | | | | | |
| Equity in losses of unconsolidated affiliates | (8) | | | (184) | | | 176 | | | | | |
| Net income | 579 | | | 1,217 | | | (638) | | | | | |
| Net (loss) income attributable to noncontrolling interests | (10) | | | 92 | | | (102) | | | | | |
| Net income attributable to membership interest | $ | 589 | | | $ | 1,125 | | | $ | (536) | | | | | |
Results of Operations—Generation
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
| Operating revenues | $ | 20,437 |
| | $ | 18,500 |
| | $ | 1,937 |
| | $ | 17,757 |
| | $ | 743 |
|
| Purchased power and fuel expense | 11,693 |
| | 9,690 |
| | (2,003 | ) | | 8,830 |
| | (860 | ) |
Revenues net of purchased power and fuel expense | 8,744 |
|
| 8,810 |
| | (66 | ) |
| 8,927 |
|
| (117 | ) |
| Other operating expenses | | | | |
|
| | | | |
| Operating and maintenance | 5,464 |
| | 6,299 |
| | 835 |
| | 5,663 |
| | (636 | ) |
| Depreciation and amortization | 1,797 |
| | 1,457 |
| | (340 | ) | | 1,879 |
| | 422 |
|
| Taxes other than income | 556 |
| | 555 |
| | (1 | ) | | 506 |
| | (49 | ) |
| Total other operating expenses | 7,817 |
|
| 8,311 |
| | 494 |
|
| 8,048 |
|
| (263 | ) |
| Gain (loss) on sales of assets and businesses | 48 |
| | 2 |
| | 46 |
| | (59 | ) | | 61 |
|
| Bargain purchase gain | — |
| | 233 |
| | (233 | ) | | — |
| | 233 |
|
| Gain on deconsolidation of business | — |
| | 213 |
| | (213 | ) | | — |
| | 213 |
|
| Operating income | 975 |
|
| 947 |
|
| 28 |
|
| 820 |
|
| 127 |
|
| Other income and (deductions) | | | | | | | | | |
| Interest expense | (432 | ) | | (440 | ) | | 8 |
| | (364 | ) | | (76 | ) |
| Other, net | (178 | ) | | 948 |
| | (1,126 | ) | | 401 |
| | 547 |
|
| Total other income and (deductions) | (610 | ) |
| 508 |
|
| (1,118 | ) |
| 37 |
|
| 471 |
|
| Income before income taxes | 365 |
|
| 1,455 |
|
| (1,090 | ) |
| 857 |
|
| 598 |
|
| Income taxes | (108 | ) | | (1,376 | ) | | (1,268 | ) | | 282 |
| | 1,658 |
|
| Equity in losses of unconsolidated affiliates | (30 | ) | | (33 | ) | | 3 |
| | (25 | ) | | (8 | ) |
| Net income | 443 |
|
| 2,798 |
|
| (2,355 | ) |
| 550 |
|
| 2,248 |
|
| Net income attributable to noncontrolling interests | 73 |
| | 88 |
| | (15 | ) | | 67 |
| | 21 |
|
| Net income attributable to membership interest | $ | 370 |
|
| $ | 2,710 |
|
| $ | (2,340 | ) |
| $ | 483 |
|
| $ | 2,227 |
|
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017. 2019. Net income attributable to membership interestinterest decreased by $2,340$536 million primarily due to:
Impacts•One-time charges and accelerated depreciation and amortization associated with Generation's decisions in the one-time remeasurementthird quarter of deferred income taxes2020 to early retire Byron and Dresden nuclear facilities in 2017 as a result2021 and Mystic Units 8 and 9 in 2024, partially offset by the absence of the TCJA;
Net unrealized losses on NDT funds in 2018 compared to net gains in 2017;
Lower realized energy prices;
Acceleratedaccelerated depreciation and amortization due to the decision to early retire the Oyster Creek andretirement of TMI nuclear facilities;in September 2019;
The gain associated with the FitzPatrick acquisition in 2017;
Increased mark-to-market losses;
The gain recorded upon deconsolidation of EGTP's net liabilities in 2017;
The absence of EGTP earnings resulting from its deconsolidation in the fourth quarter of 2017; and
Long-lived asset impairments of certain merchant wind assets in West Texas.
The decreases were partially offset by;
The impact•Impairment of the New York and Illinois ZEC revenue (including the impactEngland asset group;
•Lower capacity revenue;
•Reduction in load due to COVID-19;
Long-lived asset impairments primarily relatedGeneration
•Lower realized energy prices;
•Higher nuclear outage days;
•Impact of Generation's annual update to the EGTP assets heldnuclear ARO for sale in 2017;Non-regulatory Agreement Units;
Increased capacity prices;
The impact of lower federal income tax rate as a result of the TCJA at Generation;
Net realized gains on NDT funds; and
Decreased nuclear outage days.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.Net income attributable to membership interest increased by $2,227 million primarily due to:
Impacts associated with the one-time remeasurement of deferred income taxes as a result of the TCJA;
The gain associated with the FitzPatrick acquisition;
Accelerated depreciation and amortization due to the decision to early retire the TMI nuclear facility in 2017 compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities;
Higher•Lower net unrealized and realized gains on NDT funds;
•COVID-19 direct costs; and
The impact of the New York ZEC revenue;
The gain recorded upon deconsolidation of EGTP's net liabilities;
Increased capacity prices; and
Decreased nuclear outage days.
These increasesdecreases were partially offset by:
Long-lived asset impairments•Higher mark-to-market gains;
•Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter of 2020 and were fair valued based on quoted market prices of the stocks as of December 31, 2020;
•Lower operating and maintenance expense primarily due to previous cost management programs, lower contracting costs, and lower travel costs partially offset by lower NEIL insurance distributions;
•Lower nuclear fuel costs;
•Lower depreciation and amortization expense due to the impact of extending the operating license at Peach Bottom;
•A tax benefit related to a settlement in the EGTP assets held for sale;
Lower realized energy prices;
The conclusionfirst quarter of 2020, partially offset by the Ginna Reliability Support Services Agreement;
Increased costsabsence of a tax benefit related to certain research and development activities recorded in the acquisitionfourth quarter of the FitzPatrick nuclear facility; and2019.
Increased mark-to-market losses.
Revenues Net of Purchased Power and Fuel Expense. The basis for Generation’sGeneration's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned with these same geographic regions. Generation's sixfive reportable segments are Mid-Atlantic, Midwest, New England,York, ERCOT, and Other Power Regions. During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation will disclose five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and
Other Power Regions. See Note 24 - 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.
The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall operating revenues or results of operations. Further, the following activities are not allocated to a region and are reported in Other: amortization of certain intangible assets relating to commodity contracts recorded at fair value from mergers and acquisitions; accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.
Generation evaluates the operating performance of electric business activities using the measure of RNF. Operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy,
and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.
For the years ended December 31, 20182020 compared to 2017 and December 31, 2017 compared to 2016, 2019, RNF by region were as follows:follows. See Note 5 - Segment Information of the Combined Notes to the Consolidated Financial Statements for additional information on Purchase power and fuel expense for Generation’s reportable segments.
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | 2020 vs. 2019 |
| 2020 | | 2019 | | Variance | | % Change |
Mid-Atlantic(a) | $ | 2,204 | | | $ | 2,655 | | | $ | (451) | | | (17.0) | % |
Midwest(b) | 2,902 | | | 2,962 | | | (60) | | | (2.0) | % |
| New York | 997 | | | 1,094 | | | (97) | | | (8.9) | % |
| ERCOT | 426 | | | 308 | | | 118 | | | 38.3 | % |
| Other Power Regions | 665 | | | 620 | | | 45 | | | 7.3 | % |
| Total electric revenues net of purchased power and fuel expense | 7,194 | | | 7,639 | | | (445) | | | (5.8) | % |
| Mark-to-market gains (losses) | 295 | | | (215) | | | 510 | | | 237.2 | % |
| Other | 529 | | | 644 | | | (115) | | | (17.9) | % |
| Total revenue net of purchased power and fuel expense | $ | 8,018 | | | $ | 8,068 | | | $ | (50) | | | (0.6) | % |
__________
(a)Includes results of transactions with PECO, BGE, Pepco, DPL, and ACE.
(b)Includes results of transactions with ComEd.
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | 2018 vs. 2017 | | | | 2017 vs. 2016 |
| | 2018 | | 2017 | | Variance | | % Change | | 2016 | | Variance | | % Change |
Mid-Atlantic(a) | $ | 3,073 |
| | $ | 3,214 |
| | $ | (141 | ) | | (4.4 | )% | | $ | 3,317 |
| | $ | (103 | ) | | (3.1 | )% |
Midwest(a) | 3,135 |
| | 2,820 |
| | 315 |
| | 11.2 | % | | 2,971 |
| | (151 | ) | | (5.1 | )% |
| New England | 354 |
| | 514 |
| | (160 | ) | | (31.1 | )% | | 438 |
| | 76 |
| | 17.4 | % |
New York(c) | 1,122 |
| | 1,008 |
| | 114 |
| | 11.3 | % | | 752 |
| | 256 |
| | 34.0 | % |
| ERCOT | 258 |
| | 332 |
| | (74 | ) | | (22.3 | )% | | 281 |
| | 51 |
| | 18.1 | % |
| Other Power Regions | 375 |
| | 305 |
| | 70 |
| | 23.0 | % | | 336 |
| | (31 | ) | | (9.2 | )% |
| Total electric revenues net of purchased power and fuel expense | 8,317 |
|
| 8,193 |
|
| 124 |
| | 1.5 | % | | 8,095 |
|
| 98 |
| | 1.2 | % |
| Proprietary Trading | 42 |
| | 18 |
| | 24 |
| | n.m. |
| | 15 |
| | 3 |
| | n.m. |
|
| Mark-to-market losses | (319 | ) | | (175 | ) | | (144 | ) | | 82.3 | % | | (41 | ) | | (134 | ) | | 326.8 | % |
Other(b) | 704 |
| | 774 |
| | (70 | ) | | (9.0 | )% | | 858 |
| | (84 | ) | | (9.8 | )% |
| Total revenue net of purchased power and fuel expense | $ | 8,744 |
|
| $ | 8,810 |
|
| $ | (66 | ) | | (0.7 | )% | | $ | 8,927 |
|
| $ | (117 | ) | | (1.3 | )% |
_________ | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | 2020 vs. 2019 |
| Supply Source (GWhs) | 2020 | | 2019 | | Variance | | % Change |
Nuclear Generation(a) | | | | | | | |
| Mid-Atlantic | 52,202 | | | 58,347 | | | (6,145) | | | (10.5) | % |
| Midwest | 96,322 | | | 94,890 | | | 1,432 | | | 1.5 | % |
| New York | 26,561 | | | 28,088 | | | (1,527) | | | (5.4) | % |
| Total Nuclear Generation | 175,085 | | | 181,325 | | | (6,240) | | | (3.4) | % |
| Fossil and Renewables | | | | | | | |
| Mid-Atlantic | 2,206 | | | 2,884 | | | (678) | | | (23.5) | % |
| Midwest | 1,240 | | | 1,374 | | | (134) | | | (9.8) | % |
| New York | 4 | | | 5 | | | (1) | | | (20.0) | % |
| ERCOT | 11,982 | | | 13,572 | | | (1,590) | | | (11.7) | % |
| Other Power Regions | 11,121 | | | 11,476 | | | (355) | | | (3.1) | % |
| Total Fossil and Renewables | 26,553 | | | 29,311 | | | (2,758) | | | (9.4) | % |
| Purchased Power | | | | | | | |
Mid-Atlantic | 22,487 | | | 14,790 | | | 7,697 | | | 52.0 | % |
| Midwest | 770 | | | 1,424 | | | (654) | | | (45.9) | % |
| | | | | | | |
| ERCOT | 5,636 | | | 4,821 | | | 815 | | | 16.9 | % |
| Other Power Regions | 51,079 | | | 48,673 | | | 2,406 | | | 4.9 | % |
| Total Purchased Power | 79,972 | | | 69,708 | | | 10,264 | | | 14.7 | % |
Total Supply/Sales by Region(c) | | | | | | | |
Mid-Atlantic(b) | 76,895 | | | 76,021 | | | 874 | | | 1.1 | % |
Midwest(b) | 98,332 | | | 97,688 | | | 644 | | | 0.7 | % |
| New York | 26,565 | | | 28,093 | | | (1,528) | | | (5.4) | % |
| ERCOT | 17,618 | | | 18,393 | | | (775) | | | (4.2) | % |
| Other Power Regions | 62,200 | | | 60,149 | | | 2,051 | | | 3.4 | % |
| Total Supply/Sales by Region | 281,610 | | | 280,344 | | | 1,266 | | | 0.5 | % |
__________
(a)Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG).
(b)Includes affiliate sales to PECO, BGE, Pepco, DPL, and ACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.
(c)Reflects a decrease in load due to COVID-19.
For the years ended December 31, 2020 compared to 2019 changes in RNF by region were as follows:
| | | | | | | | | | | |
(a) | Includes results2020 vs. 2019 |
| (Decrease)/Increase | | Description |
| Mid-Atlantic | $ | (451) | | | • decreased revenue due to the permanent cease of transactions with PECO and BGEgeneration operations at TMI in the Mid-Atlantic region and resultsthird quarter of transactions with ComEd2019
• decreased capacity revenues
• lower realized energy prices, partially offset by
• increase in newly contracted load offset by impacts of COVID-19
• increased ZEC revenues due to the approval of the NJ ZEC program in the Midwest region. As a resultsecond quarter of the PHI merger, includes results of transactions with Pepco, DPL and ACE in the Mid-Atlantic region beginning on March 24, 2016.2019 |
| Midwest | (60) | | | • decreased capacity revenues
• lower realized energy prices
• decreased load due to COVID-19 offset by an increase in total ISO sales, partially offset by
• decreased nuclear outage days |
(b)New York | (97) | | | • increased nuclear outage days
• decreased ZEC revenues due to increased outage days
• lower realized energy prices
• decreased load due to COVID-19 offset by newly contracted load, partially offset by
• increased capacity revenues |
| ERCOT | 118 | | | • lower procurement costs for owned and contracted assets
• higher portfolio optimization, partially offset by
• lower realized energy prices |
Other representsPower Regions | 45 | | | • higher portfolio optimization
• increase in newly contracted load offset by impacts of COVID-19, partially offset by
• decreased capacity revenues
• lower realized energy prices |
Mark-to-market(a) | 510 | | | • gains on economic hedging activities not allocatedof $295 million in 2020 compared to a region. Includes amortizationlosses of intangible assets related to commodity contracts recorded at fair value of a $54$215 million decrease to RNF and a $57 million decrease to RNF for the years ended December 31, 2017 and 2016, respectively,in 2019 |
| Other | (115) | | | • increase in accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 - Early Plant Retirements of• decreased revenue related to the Combined Notes to Consolidated Financial Statements, of $57 million, $12 million and $60 million for the years ended December 31, 2018, 2017 and 2016, respectively, and gain on the settlement of a long-term gas supply agreement of $75 million for the year ended December 31, 2018.energy efficiency business |
| Total | $ | (50) | | | |
(c) | Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017. |
Generation’s supply sources by region are summarized below:
|
| | | | | | | | | | | | | | | | | | | | |
| | | | | | 2018 vs. 2017 | | | | 2017 vs. 2016 |
| Supply Source (GWhs) | 2018 | | 2017 | | Variance | | % Change | | 2016 | | Variance | | % Change |
Nuclear Generation(a) | | | | | | | | | | | | | |
| Mid-Atlantic | 64,099 |
| | 64,466 |
| | (367 | ) | | (0.6 | )% | | 63,447 |
| | 1,019 |
| | 1.6 | % |
| Midwest | 94,283 |
| | 93,344 |
| | 939 |
| | 1.0 | % | | 94,668 |
| | (1,324 | ) | | (1.4 | )% |
New York(c) | 26,640 |
| | 25,033 |
| | 1,607 |
| | 6.4 | % | | 18,684 |
| | 6,349 |
| | 34.0 | % |
| Total Nuclear Generation | 185,022 |
| | 182,843 |
| | 2,179 |
| | 1.2 | % | | 176,799 |
| | 6,044 |
| | 3.4 | % |
| Fossil and Renewables | | | | | | |
|
| | | | | |
|
|
| Mid-Atlantic | 3,670 |
| | 2,789 |
| | 881 |
| | 31.6 | % | | 2,731 |
| | 58 |
| | 2.1 | % |
| Midwest | 1,373 |
| | 1,482 |
| | (109 | ) | | (7.4 | )% | | 1,488 |
| | (6 | ) | | (0.4 | )% |
| New England | 4,731 |
| | 7,179 |
| | (2,448 | ) | | (34.1 | )% | | 6,968 |
| | 211 |
| | 3.0 | % |
| New York | 3 |
| | 3 |
| | — |
| | — | % | | 3 |
| | — |
| | — | % |
| ERCOT | 11,180 |
| | 12,072 |
| | (892 | ) | | (7.4 | )% | | 6,785 |
| | 5,287 |
| | 77.9 | % |
| Other Power Regions | 8,525 |
| | 6,869 |
| | 1,656 |
| | 24.1 | % | | 8,179 |
| | (1,310 | ) | | (16.0 | )% |
| Total Fossil and Renewables | 29,482 |
|
| 30,394 |
| | (912 | ) | | (3.0 | )% | | 26,154 |
|
| 4,240 |
| | 16.2 | % |
| Purchased Power | | | | | | |
|
| | | | | |
|
|
Mid-Atlantic | 6,506 |
| | 9,801 |
| | (3,295 | ) | | (33.6 | )% | | 16,874 |
| | (7,073 | ) | | (41.9 | )% |
| Midwest | 996 |
| | 1,373 |
| | (377 | ) | | (27.5 | )% | | 2,255 |
| | (882 | ) | | (39.1 | )% |
| New England | 26,033 |
| | 18,517 |
| | 7,516 |
| | 40.6 | % | | 16,632 |
| | 1,885 |
| | 11.3 | % |
| New York | — |
| | 28 |
| | (28 | ) | | — | % | | — |
| | 28 |
| | — | % |
| ERCOT | 6,550 |
| | 7,346 |
| | (796 | ) | | (10.8 | )% | | 10,637 |
| | (3,291 | ) | | (30.9 | )% |
| Other Power Regions | 18,965 |
| | 14,530 |
| | 4,435 |
| | 30.5 | % | | 13,589 |
| | 941 |
| | 6.9 | % |
| Total Purchased Power | 59,050 |
| | 51,595 |
|
| 7,455 |
| | 14.4 | % | | 59,987 |
| | (8,392 | ) | | (14.0 | )% |
| Total Supply/Sales by Region | | | | | | |
|
| | | | | |
|
|
Mid-Atlantic(b) | 74,275 |
| | 77,056 |
| | (2,781 | ) | | (3.6 | )% | | 83,052 |
| | (5,996 | ) | | (7.2 | )% |
Midwest(b) | 96,652 |
| | 96,199 |
| | 453 |
| | 0.5 | % | | 98,411 |
| | (2,212 | ) | | (2.2 | )% |
| New England | 30,764 |
| | 25,696 |
| | 5,068 |
| | 19.7 | % | | 23,600 |
| | 2,096 |
| | 8.9 | % |
| New York | 26,643 |
| | 25,064 |
| | 1,579 |
| | 6.3 | % | | 18,687 |
| | 6,377 |
| | 34.1 | % |
| ERCOT | 17,730 |
| | 19,418 |
| | (1,688 | ) | | (8.7 | )% | | 17,422 |
| | 1,996 |
| | 11.5 | % |
| Other Power Regions | 27,490 |
| | 21,399 |
| | 6,091 |
| | 28.5 | % | | 21,768 |
| | (369 | ) | | (1.7 | )% |
| Total Supply/Sales by Region | 273,554 |
|
| 264,832 |
|
| 8,722 |
| | 3.3 | % | | 262,940 |
|
| 1,892 |
| | 0.7 | % |
__________
| |
(a) | Includes the proportionate share(a)See Note 16 — Derivative Financial Instruments of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG). |
| |
(b) | Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the PHI Merger, includes affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region beginning on March 24, 2016. |
| |
(c) | Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017. |
For the years ended December 31, 2018 comparedCombined Notes to 2017Consolidated Financial Statements for additional information on mark-to-market gains and December 31, 2017 compared to 2016, changes in RNF by region were as follows:losses.
|
| | | | | | | | |
| | 2018 vs. 2017 | 2017 vs. 2016 |
| | Increase/(Decrease) | Description | Increase/(Decrease) | Description |
| Mid-Atlantic | $ | (141 | ) | • lower realized energy prices, partially offset by • increased capacity prices | $ | (103 | ) | • lower load volumes • lower realized energy prices • decreased capacity prices, partially offset by • the absence of oil inventory write-downs in 2017 • decreased nuclear outage days |
| Midwest | 315 |
| • the impact of the Illinois ZES • increased capacity prices, partially offset by • lower realized energy prices | (151 | ) | • lower realized energy prices • increased nuclear outage days, partially offset by • decreased fuel prices |
| New England | (160 | ) | • lower realized energy prices, partially offset by • increased capacity prices | 76 |
| • increased capacity prices, partially offset by • lower realized energy prices |
| New York | 114 |
| • impact of the New York CES • acquisition of Fitzpatrick, partially offset by • the conclusion of the Ginna Reliability Support Service Agreement | 256 |
| • the impact of the New York CES • acquisition of FitzPatrick, partially offset by • conclusion of the Ginna Reliability Support Service Agreement • lower realized energy prices |
| ERCOT | (74 | ) | • deconsolidation of EGTP in 2017, partially offset by • the addition of two combined-cycle gas turbines in Texas | 51 |
| • the addition of two combined-cycle gas turbines in Texas, partially offset by • lower realized energy prices |
| Other Power Regions | 70 |
| • higher realized energy prices | (31 | ) | • lower realized energy prices |
| Proprietary Trading | 24 |
| • congestion activity | 3 |
| • congestion activity |
| Mark-to-Market | (144 | ) | • losses on economic hedging activities of $319 million in 2018 compared to losses of $175 million in 2017 | (134 | ) | • losses on economic hedging activities of $175 million in 2017 compared to losses of $41 million in 2016 |
| Other | (70 | ) | • decline in revenues related to the energy efficiency business • the sale of Generation's electrical contracting business in 2018 • accelerated nuclear fuel amortization associated with announced early plant retirements, partially offset by • the absence of amortization of energy contracts recorded at fair value associated with prior acquisitions • gain on the settlement of a long-term gas supply agreement | (84 | ) | • the impacts of declining natural gas prices on Generation's natural gas portfolio • decline in revenues related to the distributed generation business, partially offset by • decrease in accelerated nuclear fuel amortization associated with announced early plant retirements |
| Total | $ | (66 | ) | | $ | (117 | ) | |
Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for the Generation-operated plants, which reflects ownership percentage of stations operated by Exelon, excluding Salem, which is operated by PSEG Nuclear, LLC and including the ownership of the FitzPatrick nuclear facility from March 31, 2017.PSEG. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.
| | | | | | | | | | | |
| 2020 | | 2019 |
| Nuclear fleet capacity factor | 95.4 | % | | 95.7 | % |
| Refueling outage days | 260 | | | 209 | |
| Non-refueling outage days | 19 | | | 51 | |
|
| | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Nuclear fleet capacity factor | 94.6 | % | | 94.1 | % | | 94.6 | % |
| Refueling outage days | 274 |
| | 293 |
| | 245 |
|
| Non-refueling outage days | 38 |
| | 53 |
| | 63 |
|
The changes in Operating and maintenance expense, consisted of the following:
|
| | | |
| | Increase (Decrease)
2018 vs. 2017(a) |
Impairment and related charges of certain generating assets(b) | $ | (432 | ) |
Merger and integration costs(c) | (68 | ) |
| Insurance | (36 | ) |
| Pension and non-pension postretirement benefits expense | (22 | ) |
| BSC costs | 13 |
|
Plant retirements and divestitures(d) | 53 |
|
| Accretion expense | (14 | ) |
| Nuclear refueling outage costs, including the co-owned Salem plant | (24 | ) |
Labor, other benefits, contracting and materials(e) | (255 | ) |
Vacation policy change(f) | 40 |
|
| Change in environmental liabilities | (45 | ) |
| Other | (45 | ) |
| Decrease in operating and maintenance expense | $ | (835 | ) |
__________
| | | | | |
(a) | Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.2020 vs. 2019 |
| Increase (Decrease) |
| Asset Impairments | $ | 499 | |
(b)ARO update | Primarily reflects the impairment of certain wind projects in 2018 and charges to earnings related to impairments as a result of the EGTP assets in 2017. |
| 125 | |
(c)Nuclear refueling outage costs, including the co-owned Salem plants | Primarily reflects merger and integration costs associated with the PHI and FitzPatrick acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. |
| 60 | |
(d)Insurance | Primarily represents the announcement to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO compared to the previous decision to early retire the TMI nuclear facility in 2017. |
| 52 | |
(e)COVID-19 direct costs | Primarily reflects decreased spending related to energy efficiency projects and decreased costs related to the sale of Generation's electrical contracting business. |
| 46 | |
(f)Litigation settlements | Primarily reflects the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy. |
|
| | | |
| | Increase (Decrease)
2017 vs. 2016(a) |
Impairment and related charges of certain generating assets (b) | $ | 307 |
|
| Merger and integration costs | 13 |
|
ARO update(c) | 84 |
|
Pension and non-pension postretirement benefits expense(c) | 10 |
|
| BSC costs | 23 |
|
Plant retirements and divestitures(d) | 127 |
|
Accretion expense(e) | 35 |
|
Nuclear refueling outage costs, including the co-owned Salem plant(f) | 104 |
|
Merger commitments(g) | (53 | ) |
Labor, other benefits, contracting and materials(h) | 38 |
|
| Cost management program | (2 | ) |
Curtailment of Generation growth and development activities(i) | (24 | ) |
Vacation policy change(j) | (40 | ) |
| Allowance for uncollectible accounts | 33 |
|
| Change in environmental liabilities | 44 |
|
| Other | (63 | ) |
| Increase in operating and maintenance expense | $ | 636 |
|
__________
| 26 | |
(a)Change in environmental liabilities | Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017. |
| 18 | |
(b)Credit loss expense(a) | Primarily reflects charges to earnings related to impairments as a result of the EGTP assets in 2017 and impairment of Upstream assets and certain wind projects in 2016. |
| 16 | |
(c)Accretion expense | Primarily reflects the non-cash benefit pursuant to the annual update of the nuclear decommissioning obligation related to the non-regulatory units in 2017 compared to 2016. |
| 14 | |
(d)Plant retirements and divestitures | Primarily represents the announcement of the early retirement of the TMI nuclear facility in 2017 compared to the previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016. |
| (8) | |
(e)Pension and non-pension postretirement benefits expense | Reflects the impact of increased accretion expenses primarily due to the acquisition of FitzPatrick on March 31, 2017. |
| (19) | |
(f)Corporate allocations | Primarily reflects an increase in the number of nuclear outage days during 2017 compared to 2016. |
| (35) | |
(g)Travel costs | Primarily represents costs incurred as part of the settlement orders approving the PHI merger during 2016. |
| (38) | |
(h)Other | Reflects increased salaries, wages and contracting costs primarily related to the acquisition of the FitzPatrick nuclear facility beginning on March 31, 2017. |
| (71) | |
(i)Labor, other benefits, contracting, and materials(b) | Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation's strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities. |
| (235) | |
(j)Total increase | Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.$ | 450 | |
__________
(a)Increased credit loss expense including impacts from COVID-19.
(b)Primarily reflects decreased costs related to the permanent cease of generation operations at TMI, lower labor costs resulting from previous cost management programs, and decreased contracting costs.
Depreciation and amortization expense for the year ended December 31, 2018 2020 compared to the year ended December 31, 2017 same period in 2019 increased primarily due to the accelerated depreciation and amortization expenses associated with theGeneration's decision to early retire the Oyster CreekByron and Dresden nuclear facility in 2018 compared tofacilities, partially offset by the previous decision to early retire the TMI nuclear facility in 2017.permanent cease of generation operations at TMI.
Depreciation and amortization expenseTaxes other than income taxes for the year ended December 31, 20172020 compared to the year ended December 31, 2016same period in 2019 decreased primarilyprimarily due to accelerated depreciationdecreased sales and increased nuclear decommissioning amortization related to the previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016 compared to the decision to early retire the TMI nuclear facility in 2017.power usage.
Gain (loss) on sales of assets and businesses for the year ended December 31, 2018 2020 compared to the year ended December 31, 2017 increasedsame period in 2019 decreased primarily due to Generation's 2018gain on sale of its electrical contracting business.certain wind assets in 2019 partially offset by the loss on sale of Oyster Creek.
Gain (loss) on sales of assets and businessesOther, net for the year ended December 31, 20172020 compared to the year ended December 31, 2016 increased primarilysame period in 2019 decreased due to certain Generation projects and contracts being terminated or renegotiated in 2016, partially offset by a gainactivity associated with Generation's sale of the retired New Boston generating site in 2016.
Bargain purchase gain for the year ended December 31, 2018 compared to the year ended December 31, 2017. decreased as a result of the gain associated with the FitzPatrick acquisition. See Note 5 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Gain on deconsolidation of business for the year ended December 31, 2018 compared to the year ended December 31, 2017 decreased due to the deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing. See Note 5 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Other, Net decreased primarily due to the net decrease in unrealized gains related to the NDT funds of Generation’s Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $45 million, $209 million
| | | | | | | | | | | |
| 2020 | | 2019 |
Net unrealized gains on NDT funds(a) | $ | 391 | | | $ | 411 | |
Net realized gains on sale of NDT funds(a) | 70 | | | 253 | |
Interest and dividend income on NDT funds(a) | 90 | | | 110 | |
Contractual elimination of income tax expense(b) | 180 | | | 216 | |
Unrealized gains from equity investments(c) | 186 | | | — | |
| Other | 20 | | | 33 | |
| Total other, net | $ | 937 | | | $ | 1,023 | |
__________
(a)Unrealized gains, realized gains, and $80 million forinterest and dividend income on the years ended December 31, 2018, 2017 and 2016 respectively, related toNDT funds are associated with the contractualNon-Regulatory Agreement Units.
(b)Contractual elimination of income tax expense (benefit)is associated with the income taxes on the NDT funds of the Regulatory Agreement Units. See Note 15 — Asset Retirement Obligations
(c)Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter of 2020 and were fair valued based on quoted market prices of the Combined Notesstocks as of December 31, 2020.
Interest Expense for the year ended December 31, 2020 compared to Consolidated Financial Statements for additional information regarding NDT funds.the same period in 2019 decreased primarily due to the redemption of long-term debt in 2020.
The following table provides unrealized and realized gains (losses) on the NDT funds of the Non-Regulatory Agreement Units:
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Net unrealized (losses) gains on NDT funds | $ | (483 | ) | | $ | 521 |
| | $ | 194 |
|
| Net realized gains on sale of NDT funds | 180 |
| | 95 |
| | 35 |
|
Effective income tax rateswere (29.5)%, (94.6)% 29.8%and 32.9%26.9% for the years ended December 31, 2018, 20172020 and 2016,2019, respectively. The increasechange in 2020 is primarily related to impacts associated withone-time income tax settlements partially offset by the one-time remeasurementabsence of deferred income taxes in 2017 as a result of the TCJA. Seeresearch and development refund claims. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional informationinformation.
Equity in losses of unconsolidated affiliates for the changeyear ended December 31, 2020 compared to the same period in 2019 increased primarily due to the impairment of equity method investments in certain distributed energy companies in the effectivethird quarter of 2019.
Net income tax rate.attributable to noncontrolling interests for the year ended December 31, 2020 compared to the same period in 2019 decreased primarily due to lower unrealized losses on NDT fund investments for CENG.
Results of Operations—ComEd
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | Favorable (Unfavorable) Variance |
| Operating revenues | $ | 5,904 | | | $ | 5,747 | | | $ | 157 | |
| | | | | |
| | | | | |
| Operating expenses | | | | | |
| Purchased power expense | 1,998 | | | 1,941 | | | (57) | |
| Operating and maintenance | 1,520 | | | 1,305 | | | (215) | |
| Depreciation and amortization | 1,133 | | | 1,033 | | | (100) | |
| Taxes other than income taxes | 299 | | | 301 | | | 2 | |
| Total operating expenses | 4,950 | | | 4,580 | | | (370) | |
| Gain on sales of assets | — | | | 4 | | | (4) | |
| Operating income | 954 | | | 1,171 | | | (217) | |
| Other income and (deductions) | | | | | |
| Interest expense, net | (382) | | | (359) | | | (23) | |
| Other, net | 43 | | | 39 | | | 4 | |
| Total other income and (deductions) | (339) | | | (320) | | | (19) | |
| Income before income taxes | 615 | | | 851 | | | (236) | |
| Income taxes | 177 | | | 163 | | | (14) | |
| Net income | $ | 438 | | | $ | 688 | | | $ | (250) | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
| Operating revenues | $ | 5,882 |
| | $ | 5,536 |
| | $ | 346 |
| | $ | 5,254 |
| | $ | 282 |
|
| Purchased power expense | 2,155 |
| | 1,641 |
| | (514 | ) | | 1,458 |
| | (183 | ) |
| Revenues net of purchased power expense | 3,727 |
| | 3,895 |
| | (168 | ) | | 3,796 |
| | 99 |
|
| Other operating expenses | | | | | | | | | |
| Operating and maintenance | 1,335 |
| | 1,427 |
| | 92 |
| | 1,530 |
| | 103 |
|
| Depreciation and amortization | 940 |
| | 850 |
| | (90 | ) | | 775 |
| | (75 | ) |
| Taxes other than income | 311 |
| | 296 |
| | (15 | ) | | 293 |
| | (3 | ) |
| Total other operating expenses | 2,586 |
| | 2,573 |
| | (13 | ) | | 2,598 |
| | 25 |
|
| Gain on sales of assets | 5 |
| | 1 |
| | 4 |
| | 7 |
| | (6 | ) |
| Operating income | 1,146 |
| | 1,323 |
| | (177 | ) | | 1,205 |
| | 118 |
|
| Other income and (deductions) | | | | | | | | | |
| Interest expense, net | (347 | ) | | (361 | ) | | 14 |
| | (461 | ) | | 100 |
|
| Other, net | 33 |
| | 22 |
| | 11 |
| | (65 | ) | | 87 |
|
| Total other income and (deductions) | (314 | ) | | (339 | ) | | 25 |
| | (526 | ) | | 187 |
|
| Income before income taxes | 832 |
| | 984 |
| | (152 | ) | | 679 |
| | 305 |
|
| Income taxes | 168 |
| | 417 |
| | 249 |
| | 301 |
| | (116 | ) |
| Net income | $ | 664 |
| | $ | 567 |
| | $ | 97 |
| | $ | 378 |
| | $ | 189 |
|
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017.2019.Net income increased decreased by $97$250 million primarily due to payments that ComEd made under the Deferred Prosecution Agreement, an impairment charge resulting from acquisition of transmission assets, and lower allowed electric distribution ROE due to a decrease in treasury rates, partially offset by higher electric distribution and energy efficiency formula rate earnings (reflecting the impacts of increased capital investment)higher rate base). The TCJA did not significantly impact Net income as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass backSee Note 19 — Commitments and Contingencies of the tax savings through customer rates.
Year Ended December 31, 2017 ComparedCombined Notes to Year Ended December 31, 2016.Net income increased $189 million primarily due to the recognition of the penalty and the after-tax interest due on the asserted penaltyConsolidated Financial Statements for additional information related to the Tax Court's decision on Exelon's like-kind exchange tax position in 2016 and increased electric distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment and higher allowed electric distribution ROE). The higher Net income was partially offset by the impact of weather conditions in 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.Deferred Prosecution Agreement.
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC and ZEC procurement costs and participation in customer choice programs. ComEd recovers electricity, REC and ZEC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact the volume of deliveries, but do impact Operating revenues related to supplied electricity.
The changes in RNFOperating revenues consisted of the following:
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
Weather(a) | $ | — |
| | $ | (36 | ) |
Volume(a) | — |
| | (5 | ) |
Pricing and customer mix(a) | — |
| | (18 | ) |
| Electric distribution revenue | (127 | ) | | 170 |
|
| Transmission revenue | (43 | ) | | 60 |
|
Energy efficiency revenue(b) | 47 |
| | 16 |
|
Regulatory required programs(b) | (97 | ) | | (85 | ) |
| Uncollectible accounts recovery, net | 6 |
| | (7 | ) |
| Other | 46 |
| | 4 |
|
| Total (decrease) increase | $ | (168 | ) | | $ | 99 |
|
__________
| | | | | |
(a) | For the year ended December 31, 2017, compared to the same period in 2016, the changes reflect the 2016 impacts of weather, volume and pricing and customer mix. Pursuant to the revenue decoupling provision in FEJA, ComEd began recording an adjustment to revenue in the first quarter of 2017 to eliminate the favorable or unfavorable impacts associated with variations in delivery volumes associated with above or below normal weather, number of customers or usage per customer.2020 vs. 2019 |
| Increase |
| Energy efficiency | $ | 37 | |
(b)Electric distribution | Beginning June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.36 | |
| Transmission | 2 | |
| Other | 29 |
| 104 | |
| Regulatory required programs | 53 |
Total increase | $ | 157 | |
Revenue Decoupling.The demand for electricity is affected by weather and customer usage. However, beginning January 1, 2017, Operating revenues are not impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms implemented pursuant to FEJA.
Energy Efficiency Revenue. FEJA provides for a changeperformance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the electric distribution formula rate pursuantactual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to FEJA.year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased for the year ended December 31, 2020, as compared to the same period in 2019, primarily due to increased regulatory asset amortization which is fully recoverable. See Depreciation and amortization expense discussions below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. During the year ended December 31, 2018,2020, as compared to the same period in 2017,2019, electric distribution revenue decreased $127 million, primarilyincreased due to the impact of the lower federal income tax rate, partially offset by increased revenues due to higher rate base and increased Depreciation expense. During the year ended December 31, 2017, as compared to the same period in 2016, electric distribution revenue increased $170 million, primarily due to increased capital investment, increased Depreciation expense, higher fully recoverable costs, offset by lower allowed ROE due to an increasea decrease in treasury rates and revenue decoupling impacts (as described above).rates. See Operating and Maintenance Expense below and Note 43 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recoveredrecovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased forDuring the year ended December 31, 2018, primarily due2020, as compared to decreased peak load and the impact of the lower federal tax rate, partially offset by increasedsame period in 2019, transmission revenues due to higher rate base and increased Depreciation expense. Transmission revenue increased for the year ended December 31, 2017, primarily due to increased capital investment, higher Depreciation expense, and increased highest daily peak load.remained relatively consistent. See Operating and Maintenance Expense below and Note 43 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Energy Efficiency Revenue. Beginning June 1, 2017, FEJA providesOther Revenue primarily includes assistance provided to other utilities through mutual assistance programs. The increase in Other revenue for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effectyear ended December 31, 2020, as compared to the actual costs that the ICC determines are prudently and reasonably incurredsame period in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. See Depreciation and amortization expense discussions below and Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.2019, primarily reflects mutual assistance revenues associated with storm restoration efforts.
Regulatory Required Programs representrepresents revenues collected under approved rate riders to recover costs incurred for regulatory programs such as purchased power administrativerecoveries under the credit loss expense tariff, environmental costs associated with MGP sites, and energy efficiencycosts related to electricity, ZEC, and demand response through June 1, 2017 pursuant to FEJA.REC procurement. The riders are designed to provide full and current cost recovery. The costs of suchthese programs are included in Operating and maintenance expense. Revenues from regulatory programs decreased for the year ended December 31, 2018, as compared to the same period in 2017, and for the year ended December 31, 2017, as compared to the same period in 2016, primarily due to the fact that beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.
Uncollectible Accounts Recovery, Net represents recoveries under the uncollectible accounts tariff. SeePurchased power expense, Operating and maintenance expense, discussion below for additional information on this tariff.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenuesDepreciation and recoveries of environmental costs associated with MGP sites. The increase in Other revenue for the years ended December 31, 2018, as compared to the same period in 2017 primarily reflects mutual assistance revenues associated with hurricane and winter storm restoration efforts. An equal and offsetting amount has been included in Operating and maintenanceamortization expense, and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd acts as the billing agent and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.
See Note 245 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The changes in Operating and maintenance expense consistedincrease of the following:
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
| Baseline | | | |
Labor, other benefits, contracting and materials(a) | $ | 20 |
| | $ | (41 | ) |
| Pension and non-pension postretirement benefits expense | — |
| | 3 |
|
| Storm costs | (19 | ) | | 2 |
|
Uncollectible accounts expense—provision(b) | 5 |
| | (6 | ) |
Uncollectible accounts expense—recovery, net(b) | 1 |
| | (1 | ) |
BSC costs(a)(c) | (5 | ) | | 44 |
|
Other(a) | 3 |
| | (19 | ) |
| | 5 |
| | (18 | ) |
| Regulatory required programs | | | |
Energy efficiency and demand response programs(d) | (97 | ) | | (85 | ) |
| Decrease in operating and maintenance expense | $ | (92 | ) | | $ | (103 | ) |
__________
| |
(a) | Includes costs associated with mutual assistance provided to other utilities in 2018. An equal and offsetting increase has been recognized in Operating revenues for the period presented. |
| |
(b) | ComEd is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. An equal and offsetting amount has been recognized in Operating revenues for the periods presented. |
| |
(c) | For the year ended December 31, 2017, primarily reflects increased information technology support services from BSC and includes the $8$57 million write-off of a regulatory asset related to Constellation merger and integration costs for which recovery is no longer expected. |
| |
(d) | Beginning June 1, 2017 ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency over the weighted average useful life of the related energy efficiency measures. |
The increases in Depreciation and amortization expense consisted of the following:
|
| | | | | | | |
| | Increase
2018 vs. 2017 | | Increase
2017 vs. 2016 |
Depreciation expense(a) | $ | 36 |
| | $ | 60 |
|
Regulatory asset amortization(b) | 53 |
| | 7 |
|
| Other | 1 |
| | 8 |
|
| Total increase | $ | 90 |
| | $ | 75 |
|
__________
| |
(a) | Primarily reflects ongoing capital expenditures. |
| |
(b) | Beginning in June 2017, includes amortization of ComEd's energy efficiency formula rate regulatory asset. |
The decrease in Interest expense, net, for the year ended 2018December 31, 2020, as compared to the same period in 2017,2019, in Purchased power expenseis offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | | |
|
2020 vs. 2019 | | |
| Increase (Decrease) | | |
Deferred Prosecution Agreement payments(a) | $ | 200 | | | |
| BSC costs | 20 | | | |
| Labor, other benefits, contracting, and materials | 7 | | | |
| Pension and non-pension postretirement benefits expense | 5 | | | |
Storm-related costs(b) | (12) | | | |
Other(c) | (4) | | | |
| 216 | | | |
Regulatory required programs(d) | (1) | | | |
Total increase | $ | 215 | | | |
| | | |
| | | |
| | | |
| | | |
__________
(a)See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
(b)For the year ended December 31, 2020, the decrease primarily reflects lower storm costs as a result of the August 2020 storm costs being reclassified to a regulatory asset.
(c)For the year ended December 31, 2020, the decrease primarily reflects lower travel costs offset by an impairment charge related to acquisition of transmission assets.
(d)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism.
The changes in Depreciation and amortization expense consisted of the following:
| | | | | | | |
|
2020 vs. 2019 | | |
| Increase | | |
Regulatory asset amortization(a) | $ | 64 | | | |
Depreciation and amortization expense(b) | 36 | | | |
| | | |
| Total increase | $ | 100 | | | |
__________
(a)Includes amortization of ComEd's energy efficiency formula rate regulatory asset and amortization related to the August 2020 storm regulatory asset.
(b)Reflects ongoing capital expenditures.
Interest Expense, net increased $23 million for the year ended 2017December 31, 2020, as compared to the same period in 2016, consisted of the following:
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
Interest expense related to uncertain tax positions(a) | $ | (13 | ) | | $ | (104 | ) |
| Interest expense on debt (including financing trusts) | 2 |
| | 6 |
|
| Other | (3 | ) | | (2 | ) |
| Decrease in interest expense, net | $ | (14 | ) | | $ | (100 | ) |
__________
| |
(a) | Primarily reflects the recognition of after-tax interest related to the Tax Court's decision on Exelon's like-kind exchange tax position in the 2016 and 2017. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. |
The increase in Other, net, for the year ended 2018 compared2019, primarily due to the same periodissuance of debt in 2017, and for the year ended 2017 compared to the same period in 2016, consisted of the following:February 2020.
|
| | | | | | | |
| | Increase
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
Other income and deductions, net(a) | $ | 1 |
| | $ | 88 |
|
| AFUDC equity | 7 |
| | (2 | ) |
| Other | 3 |
| | 1 |
|
| Increase (decrease) in Other, net | $ | 11 |
| | $ | 87 |
|
__________
| |
(a) | Primarily reflects the recognition of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in 2016. |
Effective income tax rates for the years ended December 31, 2018, 2017 2020and2019, were 28.8% and 2016, were 20.2%, 42.4% and 44.3%19.2%, respectively. The decrease in the effective income tax rate for the year ended December 31, 2018, compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. The decrease in the effective income tax rate for the year ended December 31, 2017, compared to the same period in 2016 is primarily due to the recognition of a non-deductible penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Results of Operations—PECO
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | (Unfavorable) Favorable Variance |
| Operating revenues | $ | 3,058 | | | $ | 3,100 | | | $ | (42) | |
| Operating expenses | | | | | |
| Purchased power and fuel expense | 1,018 | | | 1,029 | | | 11 | |
| Operating and maintenance | 975 | | | 861 | | | (114) | |
| Depreciation and amortization | 347 | | | 333 | | | (14) | |
| Taxes other than income taxes | 172 | | | 165 | | | (7) | |
| Total operating expenses | 2,512 | | | 2,388 | | | (124) | |
| Gain on sales of assets | — | | | 1 | | | (1) | |
| Operating income | 546 | | | 713 | | | (167) | |
| Other income and (deductions) | | | | | |
| Interest expense, net | (147) | | | (136) | | | (11) | |
| Other, net | 18 | | | 16 | | | 2 | |
| Total other income and (deductions) | (129) | | | (120) | | | (9) | |
| Income before income taxes | 417 | | | 593 | | | (176) | |
| Income taxes | (30) | | | 65 | | | 95 | |
| | | | | |
| | | | | |
| Net income | $ | 447 | | | $ | 528 | | | $ | (81) | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
| Operating revenues | $ | 3,038 |
| | $ | 2,870 |
| | $ | 168 |
| | $ | 2,994 |
| | $ | (124 | ) |
| Purchased power and fuel expense | 1,090 |
| | 969 |
| | (121 | ) | | 1,047 |
| | 78 |
|
| Revenues net of purchased power and fuel expense | 1,948 |
| | 1,901 |
| | 47 |
| | 1,947 |
| | (46 | ) |
| Other operating expenses | | | | | | | | | |
| Operating and maintenance | 898 |
| | 806 |
| | (92 | ) | | 811 |
| | 5 |
|
| Depreciation and amortization | 301 |
| | 286 |
| | (15 | ) | | 270 |
| | (16 | ) |
| Taxes other than income | 163 |
| | 154 |
| | (9 | ) | | 164 |
| | 10 |
|
| Total other operating expenses | 1,362 |
| | 1,246 |
| | (116 | ) | | 1,245 |
| | (1 | ) |
| Gain on sales of assets | 1 |
| | — |
| | 1 |
| | — |
| | — |
|
| Operating income | 587 |
| | 655 |
| | (68 | ) | | 702 |
| | (47 | ) |
| Other income and (deductions) | | | | | | | | | |
| Interest expense, net | (129 | ) | | (126 | ) | | (3 | ) | | (123 | ) | | (3 | ) |
| Other, net | 8 |
| | 9 |
| | (1 | ) | | 8 |
| | 1 |
|
| Total other income and (deductions) | (121 | ) | | (117 | ) | | (4 | ) | | (115 | ) | | (2 | ) |
| Income before income taxes | 466 |
| | 538 |
| | (72 | ) | | 587 |
| | (49 | ) |
| Income taxes | 6 |
| | 104 |
| | 98 |
| | 149 |
| | 45 |
|
| Net income | $ | 460 |
| | $ | 434 |
| | $ | 26 |
| | $ | 438 |
| | $ | (4 | ) |
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017.2019.Net income was higher due to favorable weather and volumes. The TCJA did not significantly impact Net Income as the favorable income tax impacts were predominantly offset decreased by lower revenues resulting from the requirement to pass back the tax savings through customer rates.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.Net income was lower$81 million primarily due to unfavorable weather. The TCJA did not significantly impact Net Income asweather conditions, higher storm costs due to the favorable incomeJune and August 2020 storms net of tax impacts were predominantlyrepairs, increased depreciation and amortization expense, and increased interest expense, partially offset by lower revenues resulting from the requirement to pass backfavorable volume and an increase in the tax savings through customer rates.repairs deduction.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power and fuel expenses such as commodity and REC procurement costs and participation in customer choice programs. PECO's recovers electricity, natural gas and REC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity and natural gas.
The changes in RNFOperating revenues consisted of the following:
| | | | | | | | | | | | | | | | | |
| 2020 vs. 2019 |
| (Decrease) Increase |
| Electric | | Gas | | Total |
| Weather | $ | (29) | | | $ | (21) | | | $ | (50) | |
| Volume | 12 | | | (3) | | | 9 | |
| Pricing | 2 | | | 6 | | | 8 | |
| Transmission | 11 | | | — | | | 11 | |
| Other | (7) | | | (1) | | | (8) | |
| (11) | | | (19) | | | (30) | |
| Regulatory required programs | 65 | | | (77) | | | (12) | |
| Total increase (decrease) | $ | 54 | | | $ | (96) | | | $ | (42) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 vs. 2017 | | 2017 vs. 2016 |
| | Increase (Decrease) | | Increase (Decrease) |
| | Electric | | Gas | | Total | | Electric | | Gas | | Total |
| Weather | $ | 39 |
| | $ | 22 |
| | $ | 61 |
| | $ | (28 | ) | | $ | 4 |
| | $ | (24 | ) |
| Volume | 37 |
| | 4 |
| | 41 |
| | (18 | ) | | 3 |
| | (15 | ) |
| Pricing | (75 | ) | | (1 | ) | | (76 | ) | | 8 |
| | 2 |
| | 10 |
|
| Regulatory required programs | 11 |
| | — |
| | 11 |
| | (31 | ) | | — |
| | (31 | ) |
| Other | 14 |
| | (4 | ) | | 10 |
| | 14 |
| | — |
| | 14 |
|
| Total increase (decrease) | $ | 26 |
| | $ | 21 |
| | $ | 47 |
| | $ | (55 | ) | | $ | 9 |
| | $ | (46 | ) |
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. For the year ended December 31, 20182020 compared to the same period in 2017 RNF was increased by the impact of favorable2019, Operating revenues related to weather conditions in PECO's service territory. For the year ended December 31, 2017 compareddecreased due to the same period in 2016 RNF was reduced by the impact of unfavorable weather conditions in PECO’sPECO's service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and cooling degree days in PECO’s service territory for the years ended December 31, 2018 and December 31, 20172020 compared to the same periodsperiod in 2017 and 2016, respectively,2019 and normal weather consisted of the following:
| | | | For the Years Ended December 31, | | | | % Change | | For the Years Ended December 31, | | | | % Change |
| Heating and Cooling Degree-Days | 2018 | | 2017 | | Normal | | 2018 vs. 2017 | | 2018 vs. Normal | Heating and Cooling Degree-Days | 2020 | | 2019 | | Normal | | 2020 vs. 2019 | | 2019 vs. Normal |
| Heating Degree-Days | 4,539 |
| | 3,949 |
| | 4,487 |
| | 14.9 | % | | 1.2 | % | Heating Degree-Days | 3,959 | | | 4,307 | | | 4,437 | | | (8.1) | % | | (10.8) | % |
| Cooling Degree-Days | 1,584 |
| | 1,490 |
| | 1,411 |
| | 6.3 | % | | 12.3 | % | Cooling Degree-Days | 1,521 | | | 1,610 | | | 1,423 | | | (5.5) | % | | 6.9 | % |
| | | | | | | | | | | |
| | For the Years Ended December 31, | | | | % Change | |
| Heating and Cooling Degree-Days | 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal | |
| Heating Degree-Days | 3,949 |
| | 4,041 |
| | 4,603 |
| | (2.3 | )% | | (14.2 | )% | |
| Cooling Degree-Days | 1,490 |
| | 1,726 |
| | 1,290 |
| | (13.7 | )% | | 15.5 | % | |
Volume. Delivery Electric volume, exclusive of the effects of weather, for the year ended December 31, 20182020 compared to the same period in 2017, was driven2019, increased due to an increase in usage for residential customers during COVID-19 further increased by electric and primarily reflects the impact of moderate economic and customer growth partially offset by the impact of energy efficiency initiatives on customer usages primarily in the residential class. Additionally, the increase represents a shift in thegrowth. Natural gas volume profile across classes from the commercial and industrial classes to the residential class.
Delivery volume, exclusive of the effects of weather, for the year ended December 31, 20172020 compared to the same period in 2016, was driven by electric and primarily reflects2019, decreased on a net basis due to a decrease in usage for the impact of energy efficiency initiatives on customer usages for residential and small commercial and industrial electricnatural gas classes partially offset by solid customer growth. Additionally, the decrease represents a shift in the volume profile across classes from residential and small commercial and industrial to large commercial and industrial.during COVID-19.
| | | Electric Retail Deliveries to Customers (in GWhs) | 2018 | | 2017 | | % Change 2018 vs. 2017 | | Weather - Normal % Change | | 2016 | | % Change 2017 vs. 2016 | | Weather - Normal % Change | Electric Retail Deliveries to Customers (in GWhs) | 2020 | | 2019 | | % Change 2020 vs. 2019 | | Weather - Normal % Change(b) |
Retail Deliveries (a) | | | | | | | | | | | | | | Retail Deliveries(a) | | | | | | | |
| Residential | 14,005 |
| | 13,024 |
| | 7.5 | % | | 3.5 | % | | 13,664 |
| | (4.7 | )% | | (1.8 | )% | Residential | 14,041 | | | 13,650 | | | 2.9 | % | | 5.6 | % |
| Small commercial & industrial | 8,177 |
| | 7,968 |
| | 2.6 | % | | 0.2 | % | | 8,099 |
| | (1.6 | )% | | (1.1 | )% | Small commercial & industrial | 7,210 | | | 7,983 | | | (9.7) | % | | (8.2) | % |
| Large commercial & industrial | 15,516 |
| | 15,426 |
| | 0.6 | % | | 0.4 | % | | 15,263 |
| | 1.1 | % | | 1.4 | % | Large commercial & industrial | 13,669 | | | 14,958 | | | (8.6) | % | | (8.5) | % |
| Public authorities & electric railroads | 761 |
| | 809 |
| | (5.9 | )% | | (5.6 | )% | | 890 |
| | (9.1 | )% | | (9.1 | )% | Public authorities & electric railroads | 575 | | | 725 | | | (20.7) | % | | (20.7) | % |
| Total electric retail deliveries | 38,459 |
| | 37,227 |
| | 3.3 | % | | 1.4 | % | | 37,916 |
| | (1.8 | )% | | (0.5 | )% | Total electric retail deliveries | 35,495 | | | 37,316 | | | (4.9) | % | | (3.5) | % |
__________
| |
(a) | Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. |
(a)Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. |
| | | | | | | | |
| | As of December 31, |
| Number of Electric Customers | 2018 | | 2017 | | 2016 |
| Residential | 1,480,925 |
| | 1,469,916 |
| | 1,456,585 |
|
| Small commercial & industrial | 152,797 |
| | 151,552 |
| | 150,142 |
|
| Large commercial & industrial | 3,118 |
| | 3,112 |
| | 3,096 |
|
| Public authorities & electric railroads | 9,565 |
| | 9,569 |
| | 9,823 |
|
| Total | 1,646,405 |
| | 1,634,149 |
| | 1,619,646 |
|
| | | | | | | | | | | |
| | As of December 31, |
| Number of Electric Customers | 2020 | | 2019 |
| Residential | 1,508,622 | | | 1,494,462 | |
| Small commercial & industrial | 154,421 | | | 154,000 | |
| Large commercial & industrial | 3,101 | | | 3,104 | |
| Public authorities & electric railroads | 10,206 | | | 10,039 | |
| Total | 1,676,350 | | | 1,661,605 | |
| | | Natural Gas Deliveries to customers (in mmcf) | 2018 | | 2017 | | % Change 2018 vs. 2017 | | Weather- Normal % Change | | 2016 | | % Change 2017 vs. 2016 | | Weather- Normal % Change | Natural Gas Deliveries to customers (in mmcf) | 2020 | | 2019 | | % Change 2020 vs. 2019 | | Weather - Normal % Change(b) |
Retail Deliveries (a) | | | | | | | | | | | | | | Retail Deliveries(a) | | | | | | | |
| Residential | 43,450 |
| | 37,919 |
| | 14.6 | % | | 1.8 | % | | 36,872 |
| | 2.8 | % | | 0.6 | % | Residential | 38,272 | | | 40,196 | | | (4.8) | % | | 1.6 | % |
| Small commercial & industrial | 21,997 |
| | 20,515 |
| | 7.2 | % | | (0.4 | )% | | 19,525 |
| | 5.1 | % | | 1.9 | % | Small commercial & industrial | 19,341 | | | 23,828 | | | (18.8) | % | | (6.6) | % |
| Large commercial & industrial | 65 |
| | 23 |
| | 182.6 | % | | 175.8 | % | | 50 |
| | (54.0 | )% | | 28.3 | % | Large commercial & industrial | 36 | | | 50 | | | (28.0) | % | | (11.9) | % |
| Transportation | 26,595 |
| | 26,382 |
| | 0.8 | % | | (3.2 | )% | | 27,630 |
| | (4.5 | )% | | (2.3 | )% | Transportation | 24,533 | | | 25,822 | | | (5.0) | % | | (2.9) | % |
| Total natural gas deliveries | 92,107 |
| | 84,839 |
| | 8.6 | % | | (0.2 | )% | | 84,077 |
| | 0.9 | % | | 0.1 | % | Total natural gas deliveries | 82,182 | | | 89,896 | | | (8.6) | % | | (1.8) | % |
__________
| |
(a) | Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. |
(a)Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
| | | | As of December 31, | | As of December 31, |
| Number of Gas Customers | 2018 | | 2017 | | 2016 | Number of Gas Customers | 2020 | | 2019 |
| Residential | 482,255 |
| | 477,213 |
| | 472,606 |
| Residential | 492,298 | | | 487,337 | |
| Small commercial & industrial | 44,170 |
| | 43,887 |
| | 43,664 |
| Small commercial & industrial | 44,472 | | | 44,374 | |
| Large commercial & industrial | 1 |
| | 5 |
| | 4 |
| Large commercial & industrial | 5 | | | 2 | |
| Transportation | 754 |
| | 771 |
| | 790 |
| Transportation | 713 | | | 730 | |
| Total | 527,180 |
| | 521,876 |
| | 517,064 |
| Total | 537,488 | | | 532,443 | |
Pricing for the year ended December 31, 20182020 compared to the same period in 2017 reflects the anticipated pass back of the Tax Cuts and Jobs Act tax savings through customer rates.
The increase in Operating revenues net of purchased power and fuel expense as a result of pricing for the year ended December 31, 2017 compared2019 increased primarily due to the same period in 2016 reflects higher overall effective rates due to decreased usage across all major customer classes. Additionally, the increase represents revenue from higher natural gas distribution rates.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the residentialunderlying costs and small commercialcapital investments being recovered. PECO's transmission formula rate filing was approved in the fourth quarter of 2019.
Other Revenue primarily includes revenue related to late payment charges. Other revenues for the year ended December 31, 2020 compared to the same period in 2019, decreased as PECO ceased new late fees for all customers and industrial customer classes. Operating revenues netrestored service to customers upon request who were disconnected in the last twelve months beginning March of fuel expense as a result of pricing remained relatively consistent. See Note 4 — Regulatory Matters for additional information.2020.
Regulatory Required Programs represent represents revenues collected under approved riders to recover costs incurred for regulatory programs such as smart meter, energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes.
Other revenue includes rental revenue, revenue Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to late payment charges, mutual assistancethe electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and wholesale transmission revenue.Purchased power and fuel expense related to the electricity, natural gas, and RECs.
See Note 24—5—Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The changes in Operating and maintenance expense consisteddecrease of the following:
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
| Baseline | | | |
| Labor, other benefits, contracting and materials | $ | 10 |
| | $ | 17 |
|
Storm-related costs (a) | 63 |
| | (7 | ) |
| Pension and non-pension postretirement benefits expense | (7 | ) | | (3 | ) |
| BSC costs | — |
| | 4 |
|
| Uncollectible accounts expense | 7 |
| | (5 | ) |
| Other | 9 |
| | — |
|
| | 82 |
| | 6 |
|
| Regulatory required programs | | | |
| Energy efficiency | 10 |
| | (10 | ) |
| Other | — |
| | (1 | ) |
| | 10 |
| | (11 | ) |
| Increase (decrease) in operating and maintenance expense | $ | 92 |
| | $ | (5 | ) |
__________
(a) Reflects increased costs incurred from the Q1 2018 winter storms.
The changes in Depreciation and amortization expense consisted of the following:
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
Depreciation expense (a) | $ | 13 |
| | $ | 17 |
|
| Regulatory asset amortization | 2 |
| | (1 | ) |
| Increase in depreciation and amortization expense | $ | 15 |
|
| $ | 16 |
|
__________(a) Depreciation expense increased due to ongoing capital expenditures.
Taxes other than income increased$11 million for the year ended December 31, 2018,2020 compared to the same period in 2017,2019, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | |
|
2020 vs. 2019 | |
| Increase (Decrease) | |
| | |
Storm-related costs(a) | $ | 82 | | |
| Labor, other benefits, contracting, and materials | 23 | | |
| | |
| | |
Credit loss expense(b) | 12 | | |
| BSC costs | 1 | | |
| Pension and non-pension postretirement benefits expense | (4) | | |
| Other | 7 | | |
| 121 | | |
| Regulatory Required Programs | (7) | | |
| Total increase | $ | 114 | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
__________
(a)Reflects increased storm costs due to June and August 2020 storms.
(b)Increased credit loss expense primarily as a result of suspending customer disconnections, partially offset by the regulatory asset recorded in 2020 related to incremental credit loss expense due to COVID-19. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:
| | | | | |
| 2020 vs. 2019 |
| Increase (Decrease) |
Depreciation and amortization(a) | $ | 16 | |
| |
| |
| Regulatory asset amortization | (2) | |
| |
| Total increase | $ | 14 | |
__________
(a)Depreciation and amortization expense increased primarily due to an increase in gross receipts tax driven by ongoing capital expenditures.
Interest expense, net increased electric revenue.
Taxes other than income decreased$11 million for the year ended December 31, 2017,2020 compared to the same period in 2016,2019, respectively, primarily due to a decreasethe issuance of debt in gross receipts tax driven by decreases in electric revenue.June 2020.
Effective income tax rates were 1.3%, 19.3%(7.2)% and 25.4%11.0% for the years ended December 31, 2018, 20172020 and 2016,2019, respectively. The decrease is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information of the change in effective income tax rates.
Results of Operations—BGE
| | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | (Unfavorable) Favorable Variance | | | | |
| Operating revenues | $ | 3,098 | | | $ | 3,106 | | | $ | (8) | | | | | |
| Operating expenses | | | | | | | | | |
| Purchased power and fuel expense | 991 | | | 1,052 | | | 61 | | | | | |
| Operating and maintenance | 789 | | | 760 | | | (29) | | | | | |
| Depreciation and amortization | 550 | | | 502 | | | (48) | | | | | |
| Taxes other than income taxes | 268 | | | 260 | | | (8) | | | | | |
| Total operating expenses | 2,598 | | | 2,574 | | | (24) | | | | | |
| | | | | | | | | |
| Operating income | 500 | | | 532 | | | (32) | | | | | |
| Other income and (deductions) | | | | | | | | | |
| Interest expense, net | (133) | | | (121) | | | (12) | | | | | |
| Other, net | 23 | | | 28 | | | (5) | | | | | |
| Total other income and (deductions) | (110) | | | (93) | | | (17) | | | | | |
| Income before income taxes | 390 | | | 439 | | | (49) | | | | | |
| Income taxes | 41 | | | 79 | | | 38 | | | | | |
| Net income | $ | 349 | | | $ | 360 | | | $ | (11) | | | | | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
| Operating revenues | $ | 3,169 |
| | $ | 3,176 |
| | $ | (7 | ) | | $ | 3,233 |
| | $ | (57 | ) |
| Purchased power and fuel expense | 1,182 |
| | 1,133 |
| | (49 | ) | | 1,294 |
| | 161 |
|
| Revenues net of purchased power and fuel expense | 1,987 |
| | 2,043 |
| | (56 | ) | | 1,939 |
| | 104 |
|
| Other operating expenses | | | | | | | | | |
| Operating and maintenance | 777 |
| | 716 |
| | (61 | ) | | 737 |
| | 21 |
|
| Depreciation and amortization | 483 |
| | 473 |
| | (10 | ) | | 423 |
| | (50 | ) |
| Taxes other than income | 254 |
| | 240 |
| | (14 | ) | | 229 |
| | (11 | ) |
| Total other operating expenses | 1,514 |
| | 1,429 |
| | (85 | ) | | 1,389 |
| | (40 | ) |
| Gain on sales of assets | 1 |
| | — |
| | 1 |
| | — |
| | — |
|
| Operating income | 474 |
| | 614 |
| | (140 | ) | | 550 |
| | 64 |
|
| Other income and (deductions) | | | | | | | | | |
| Interest expense, net | (106 | ) | | (105 | ) | | (1 | ) | | (103 | ) | | (2 | ) |
| Other, net | 19 |
| | 16 |
| | 3 |
| | 21 |
| | (5 | ) |
| Total other income and (deductions) | (87 | ) | | (89 | ) | | 2 |
| | (82 | ) | | (7 | ) |
| Income before income taxes | 387 |
| | 525 |
| | (138 | ) | | 468 |
| | 57 |
|
| Income taxes | 74 |
| | 218 |
| | 144 |
| | 174 |
| | (44 | ) |
| Net income | 313 |
| | 307 |
| | 6 |
| | 294 |
| | 13 |
|
| Preference stock dividends | — |
| | — |
| | — |
| | 8 |
| | 8 |
|
| Net income attributable to common shareholder | $ | 313 |
| | $ | 307 |
| | $ | 6 |
| | $ | 286 |
| | $ | 21 |
|
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017.2019.Net income attributable to common shareholder increased by $6 million remained relatively consistent primarily due to an increase in transmission formula rate revenueshigher natural gas and the absence of the 2017 impairment of certain transmission-related income tax regulatory assetselectric distribution rates, partially offset by increased storm restoration costs as a result of storms in March 2018depreciation and September 2018. The TCJA did not significantly impact Net income attributable to common shareholder as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.Net income attributable to common shareholderamortization expense, increased by $21 million primarilyinterest expense, increased expense due to the impacts of the electrica commitment to a multi-year small business grants program, and natural gas distribution rate orders issued by the MDPSCa decrease in June 2016 and July 2016, an increase in transmission formula rate revenues, the absence of cost disallowances resulting from the 2016 distribution rate orders issued by the MDPSC, and decreased storm costs in 2017. These increases were partially offset by the favorable 2016 settlement of the Baltimore City conduit fee dispute, the initiation of cost recovery of the AMI programs under the distribution rate orders and increased capital investment, higher income tax expense primarily resulting from higher taxable income as well as a 2016 favorable adjustment, and the 2017 impairment of certain transmission-related income tax regulatory assets.other revenues.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity procurement costs and participation in customer choice programs. BGE recovers electricity, natural gas and other procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity and natural gas from electric generation and natural gas competitive suppliers. Customer choice programs do not impact the volume of deliveries or RNF but impact Operating revenues related to supplied electricity and natural gas.
The changes in RNFOperating revenues consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | |
| 2020 vs. 2019 | | |
| Increase (Decrease) | | |
| Electric | | Gas | | Total | | | | | | |
| Distribution | $ | 30 | | | $ | 54 | | | $ | 84 | | | | | | | |
| Transmission | (3) | | | — | | | (3) | | | | | | | |
| Other | (14) | | | (9) | | | (23) | | | | | | | |
| 13 | | | 45 | | | 58 | | | | | | | |
| Regulatory required programs | (55) | | | (11) | | | (66) | | | | | | | |
| Total (decrease) increase | $ | (42) | | | $ | 34 | | | $ | (8) | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 vs. 2017 | | 2017 vs. 2016 |
| | Increase (Decrease) | | Increase (Decrease) |
| | Electric | | Gas | | Total | | Electric | | Gas | | Total |
| Distribution rate increase (decrease) | $ | (62 | ) | | $ | (28 | ) | | $ | (90 | ) | | $ | 21 |
| | $ | 29 |
| | $ | 50 |
|
| Regulatory required programs | 2 |
| | 2 |
| | 4 |
| | 17 |
| | 3 |
| | 20 |
|
| Transmission revenue | 15 |
| | — |
| | 15 |
| | 18 |
| | — |
| | 18 |
|
| Other, net | 5 |
| | 10 |
| | 15 |
| | 5 |
| | 11 |
| | 16 |
|
| Total (decrease) increase | $ | (40 | ) | | $ | (16 | ) |
| $ | (56 | ) | | $ | 61 |
| | $ | 43 |
| | $ | 104 |
|
Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
| | | | | | | | | | | | | |
| As of December 31, | | |
| Number of Electric Customers | 2020 | | 2019 | | |
| Residential | 1,190,678 | | | 1,177,333 | | | |
| Small commercial & industrial | 114,173 | | | 114,504 | | | |
| Large commercial & industrial | 12,478 | | | 12,322 | | | |
| Public authorities & electric railroads | 267 | | | 268 | | | |
| Total | 1,317,596 | | | 1,304,427 | | | |
| | | | | | | | | As of December 31, | |
| | As of December 31, | |
| Number of Electric Customers | 2018 | | 2017 | | 2016 | |
| Number of Gas Customers | | Number of Gas Customers | 2020 | | 2019 | |
| Residential | 1,168,372 |
| | 1,160,783 |
| | 1,150,096 |
| Residential | 647,188 | | | 639,426 | | |
| Small commercial & industrial | 113,915 |
| | 113,594 |
| | 113,230 |
| Small commercial & industrial | 38,267 | | | 38,345 | | |
| Large commercial & industrial | 12,253 |
| | 12,155 |
| | 12,053 |
| Large commercial & industrial | 6,101 | | | 6,037 | | |
| Public authorities & electric railroads | 262 |
| | 272 |
| | 280 |
| |
| Total | 1,294,802 |
| | 1,286,804 |
| | 1,275,659 |
| Total | 691,556 | | | 683,808 | | |
|
| | | | | | | | |
| | As of December 31, |
| Number of Gas Customers | 2018 | | 2017 | | 2016 |
| Residential | 633,757 |
| | 629,690 |
| | 623,647 |
|
| Small commercial & industrial | 38,332 |
| | 38,392 |
| | 37,941 |
|
| Large commercial & industrial | 5,954 |
| | 5,855 |
| | 6,314 |
|
| Total | 678,043 |
| | 673,937 |
| | 667,902 |
|
Distribution Revenues decreased duringRevenue increased for the year ended December 31, 2018,2020 compared to the same period in 2017,2019, primarily due to the impact of reducedhigher natural gas and electric distribution rates to reflect the lower federal income tax rate and increased during the year ended December 31, 2017, compared to the same period in 2016, primarily due to the impact of the electric and natural gas distribution rate changes that became effective in June 2016 in accordance with the electric and natural gas distribution rate case orders in June 2016 and July 2016. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.December 2019.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are
designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.
Transmission Revenue. Under a FERC approvedFERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased duringdecreased for the yearsyear ended December 31, 2018 and 20172020 compared to the same period in 2019, primarily due to increases in capital investment and operating and maintenance expense recoveries.the settlement agreement of transmission-related income tax regulatory liabilities, partially offset by higher fully recoverable costs. See Operating and maintenance expense below and Note 43 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue Revenue includes revenue related to late payment charges, mutual assistance, revenues, off-system sales, and service application fees. Other revenue decreased for the year ended December 31, 2020 compared to the same period in 2019, as BGE temporarily suspended customer disconnections for non-payment beginning March of 2020 and temporarily ceased new late fees for all customers and restored service to customers upon request who were disconnected in the last twelve months.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.
See Note 245 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The decrease of $61 million for the year ended December 31, 2020 compared to the same period in 2019, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
| Baseline | | | |
Impairment on long-lived assets and losses on regulatory assets(a) | $ | — |
| | $ | (50 | ) |
| Labor, other benefits, contracting and materials | 18 |
| | (11 | ) |
| Pension and non-pension postretirement benefits expense | (2 | ) | | — |
|
Storm-related costs(b) | 39 |
| | (13 | ) |
| Uncollectible accounts expense | 2 |
| | 7 |
|
| BSC costs | 7 |
| | 16 |
|
Conduit lease settlement(c) | — |
| | 15 |
|
| Other | 3 |
| | 7 |
|
| | $ | 67 |
| | $ | (29 | ) |
| Regulatory Required Programs | | | |
| Other | (6 | ) | | 8 |
|
| Total (decrease) increase | $ | 61 |
| | $ | (21 | ) |
__________
| | | | | | | |
(a) | See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on Smart Meter and Smart Grid Investments.2020 vs. 2019 |
| |
(b) | Reflects increased storm restoration costs incurred from storms in Q1 2018 and Q3 2018.Increase (Decrease) |
| |
(c)Small business grants commitment(a) | See Note 22 — Commitments$ | 15 | | | |
| BSC costs | 13 | | | |
| | | |
Credit loss expense(b) | 7 | | | |
| | | |
Labor, other benefits, contracting, and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.materials | (1) | | | |
| Pension and non-pension postretirement benefits expense | (2) | | | |
| | | |
| | | |
| 32 | | | |
| Regulatory required programs | (3) | | | |
| Total increase | $ | 29 | | | |
__________
(a)Reflects increased charitable contributions as a result of a commitment in 2020 to a multi-year small business grants program.
(b)Increased credit loss expense primarily as a result of suspending customer disconnections, partially offset by the regulatory asset recorded in 2020 related to incremental credit loss expense due to COVID-19. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
Depreciation expense(a) | $ | 25 |
| | $ | 13 |
|
Regulatory asset amortization(b) | (24 | ) | | 25 |
|
| Regulatory required programs | 9 |
| | 12 |
|
| Increase in depreciation and amortization expense | $ | 10 |
| | $ | 50 |
|
__________
| | | | | | | |
(a) | Depreciation expense increased due to ongoing capital expenditures.2020 vs. 2019 |
| |
(b) | Increase | | |
Depreciation and amortization(a) | $ | 35 | | | |
| Regulatory required programs | 10 | | | |
Regulatory asset amortization decreased for the year ended December 31, 2018 compared to the same period in 2017, primarily due to certain regulatory assets that became fully amortized as of December 31, 2017 and increased for the year ended December 31, 2017 compared to the same period in 2016, primarily due to energy efficiency programs and the initiation of cost recovery of the AMI programs under the final electric and natural gas distribution rate case order issued by the MDPSC in June 2016. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. | 3 | | | |
| Total increase | $ | 48 | | | |
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Taxes other than income increased for the year ended December 31, 20182020 compared to the same period in 2017, and2019, primarily due to higher property taxes.
Interest expense, net increased for the year ended December 31, 20172020 compared to the same period in 2016,2019, primarily due to an increasethe issuance of debt in property taxes.September 2019 and June 2020.
Effective income tax rates were 19.1%, 41.5%10.5% and 37.2%18.0% for the years ended December 31, 2018, 20172020 and 2016,2019, respectively. Income taxes decreased for the year ended December 31, 2018 comparedThe change is primarily related to the same period in 2017, primarily due to the lower federalsettlement agreement of transmission-related income tax rate as a result of the TCJA.regulatory liabilities. See Note 3 — Regulatory Matters and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Results of Operations—PHI
PHI’s resultsResults of operationsOperations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI's corporate operations include interest costs from various financing activities. For "Predecessor" reporting periods, PHI's results of operations also include the results of PES and PCI. See Note 24 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding PHI's reportable segments. All material intercompany accounts and transactions have been eliminated in consolidation.
The following tablestable sets forth PHI's GAAP consolidated Net Income (Loss) by Registrant. As a result of the PHI Merger, the tables present two separate reporting periods for 2016. The "Predecessor" reporting periods represent PHI's results of operationsRegistrant for the period of January 1, 2016 to March 23, 2016. The "Successor" reporting periods represents PHI's results of operations for the yearsyear ended December 31, 2018 and 2017 as well as March 24, 20162020 compared to December 31, 2016.the same period in 2019. See the resultsResults of operationsOperations for Pepco, DPL, and ACE for additional information by segment.information.
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | Favorable (Unfavorable) Variance |
| PHI | $ | 495 | | | $ | 477 | | | $ | 18 | |
| Pepco | 266 | | | 243 | | | 23 | |
| DPL | 125 | | | 147 | | | (22) | |
| ACE | 112 | | | 99 | | | 13 | |
Other(a) | (8) | | | (12) | | | 4 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the Years Ended December 31, | | Favorable (unfavorable) 2018 vs. 2017 variance | | March 24 to December 31, | | | January 1 to
March 23, |
| | 2018 | | 2017 | | | 2016 | | | 2016 |
| PHI | $ | 398 |
| | $ | 362 |
| | $ | 36 |
| | $ | (61 | ) | | | $ | 19 |
|
(a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, | | Favorable (unfavorable) 2018 vs. 2017 variance | | For the Years Ended December 31, | | Favorable (unfavorable) 2017 vs. 2016 variance |
| | 2018 | | 2017 | | | 2017 | | 2016 | |
| Pepco | $ | 210 |
| | $ | 205 |
| | $ | 5 |
| | $ | 205 |
| | $ | 42 |
| | $ | 163 |
|
| DPL | 120 |
| | 121 |
| | (1 | ) | | 121 |
| | (9 | ) | | 130 |
|
| ACE | 75 |
| | 77 |
| | (2 | ) | | 77 |
| | (42 | ) | | 119 |
|
Other(a) | (7 | ) | | (41 | ) | | 34 |
| | (41 | ) | | n/a |
| | n/a |
|
_________ | |
(a) | Primarily includes eliminating and consolidating adjustments, PHI’s corporate operations, shared service entities and other financing activities. Not included for 2016 due to PHI Predecessor periods not being comparable. |
Successor Year Ended December 31, 2018 Compared to Successor Year Ended December 31, 2017. Net income increased by $36 million primarily due to distribution rate increases (not reflecting the impact of the TCJA), favorable weather and volume, the absence of 2017 impairments of certain transmission-related income tax regulatory assets and the DC sponsorship intangible asset, partially offset by an increase in asset retirement obligations primarily related to asbestos identified at the Buzzard Point property and the deferral of accumulated merger integration cost as regulatory assets in 2017. The TCJA did not significantly impact Net income as the favorable tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Successor Period of March 24, 2016 to December 31, 2016. Net loss for the Successor period of March 24, 2016 to December 31, 2016 was $61 million. There were no significant changes in the underlying trends affecting PHI's results of operations during the Successor period March 24, 2016 to December 31, 2016 except for the pre-tax recording of $392 million of non-recurring merger-related costs including merger integration and merger commitments within Operating and maintenance expense.
Predecessor Period ofJanuary 1, 2016 to March 23, 2016. Net income for the Predecessor period of January 1, 2016 to March 23, 2016 was $19 million. There were no significant changes in the underlying trends affecting PHI's results of operations during the Predecessor period of January 1, 2016 to March 23, 2016 except for the pre-tax recording of $29 million of non-recurring merger-related costs within Operating and maintenance expense and $18 million of preferred stock derivative expense within Other, net.
Results of Operations—Pepco
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
| Operating revenues | $ | 2,239 |
| | $ | 2,158 |
| | $ | 81 |
| | $ | 2,186 |
| | $ | (28 | ) |
| Purchased power expense | 654 |
| | 614 |
| | (40 | ) | | 706 |
| | 92 |
|
| Revenues net of purchased power expense | 1,585 |
| | 1,544 |
| | 41 |
| | 1,480 |
| | 64 |
|
| Other operating expenses | | | | | | | | | |
| Operating and maintenance | 501 |
| | 454 |
| | (47 | ) | | 642 |
| | 188 |
|
| Depreciation and amortization | 385 |
| | 321 |
| | (64 | ) | | 295 |
| | (26 | ) |
| Taxes other than income | 379 |
| | 371 |
| | (8 | ) | | 377 |
| | 6 |
|
| Total other operating expenses | 1,265 |
| | 1,146 |
| | (119 | ) | | 1,314 |
| | 168 |
|
| Gain on sales of assets | — |
| | 1 |
| | (1 | ) | | 8 |
| | (7 | ) |
| Operating income | 320 |
| | 399 |
| | (79 | ) | | 174 |
| | 225 |
|
| Other income and (deductions) | | | | | | | | | |
| Interest expense, net | (128 | ) | | (121 | ) | | (7 | ) | | (127 | ) | | 6 |
|
| Other, net | 31 |
| | 32 |
| | (1 | ) | | 36 |
| | (4 | ) |
| Total other income and (deductions) | (97 | ) | | (89 | ) | | (8 | ) | | (91 | ) | | 2 |
|
| Income before income taxes | 223 |
| | 310 |
| | (87 | ) | | 83 |
| | 227 |
|
| Income taxes | 13 |
| | 105 |
| | 92 |
| | 41 |
| | (64 | ) |
| Net income | $ | 210 |
| | $ | 205 |
| | $ | 5 |
| | $ | 42 |
| | $ | 163 |
|
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017.2019. Net income increased by $5$18 million primarily due to higher electric distribution base rates, (not reflectinghigher transmission rates (net of the impact of the TCJA)settlement agreement of ongoing transmission-related income tax regulatory liabilities), and decreased expense resulting from an absence of an increase in Maryland that became effective October 2017environmental liabilities, and June 2018 and higher electric distribution base rates (not reflecting the impacta gain on sale of the TCJA)land at Pepco in the Districtfourth quarter of Columbia that became effective August 2017 and August 2018,2020, partially offset by an increase in asset retirement obligationsdepreciation and amortization expense, an increase in DPL storm costs related primarily to the Buzzard Point property, deferralAugust 2020 storms in Delaware, an increase in credit loss expense primarily as a result of accumulated merger integration costs as regulatory assets in 2017 and highersuspending customer disconnections partially offset by the regulatory asset amortizationrecorded in 2020 related to incremental credit loss expense due to additional regulatory assets related to rate case activity. The TCJA did not significantly impact Net income as the favorable tax impacts were predominantly offset by lower revenues resulting from pass backCOVID-19, and unfavorable weather conditions in ACE and DPL Delaware's service territories.
Results of Operations—Pepco
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | (Unfavorable) Favorable Variance |
| Operating revenues | $ | 2,149 | | | $ | 2,260 | | | $ | (111) | |
| Operating expenses | | | | | |
| Purchased power expense | 602 | | | 665 | | | 63 | |
| Operating and maintenance | 453 | | | 482 | | | 29 | |
| Depreciation and amortization | 377 | | | 374 | | | (3) | |
| Taxes other than income taxes | 367 | | | 378 | | | 11 | |
| Total operating expenses | 1,799 | | | 1,899 | | | 100 | |
| Gain on sales of assets | 9 | | | — | | | 9 | |
| Operating income | 359 | | | 361 | | | (2) | |
| Other income and (deductions) | | | | | |
| Interest expense, net | (138) | | | (133) | | | (5) | |
| Other, net | 38 | | | 31 | | | 7 | |
| Total other income and (deductions) | (100) | | | (102) | | | 2 | |
| Income before income taxes | 259 | | | 259 | | | — | |
| Income taxes | (7) | | | 16 | | | 23 | |
| Net income | $ | 266 | | | $ | 243 | | | $ | 23 | |
Year Ended December 31, 20172020 Compared to Year Ended December 31, 2016.2019.Net income increased by $163$23 million primarily due to a decreasedecreased expense resulting from an absence of an increase in Operating and maintenance expense due to merger-related costs recognized in March 2016, higherenvironmental liabilities, increased electric distribution base rates in Maryland that became effective November 2016revenues, and October 2017 and higher electric distribution base ratesa gain on sale of land in the District of Columbia that became effective August 2017, partially offset by higher depreciation expense due to increased depreciation rates in Maryland effective November 2016. Income taxes expense included unrecognized tax benefits of $21 million for uncertain tax positions related to the deductibility of certain merger commitments in the firstfourth quarter of 2017. This decrease was2020, partially offset by an increase in income taxesdepreciation and amortization expense and an increase in credit loss expense primarily as a result of suspending customer disconnections partially offset by the regulatory asset recorded in 2020 related to incremental credit loss expense due to the $14 million December 2017 impairment of certain transmission related income tax regulatory assets.COVID-19.
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity and REC procurement costs and participation in customer choice programs. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up. Therefore, fluctuations in these costs have minimal impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity.
The changes in RNFOperating revenues consisted of the following:
| | | | | | | |
| 2020 vs. 2019 | | |
| Increase (Decrease) | | |
| Distribution | 19 | | | |
| Transmission | (36) | | | |
| Other | (3) | | | |
| (20) | | | |
| Regulatory required programs | (91) | | | |
| Total decrease | $ | (111) | | | |
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
| Volume | $ | 12 |
| | $ | 16 |
|
| Distribution revenue | (3 | ) | | 66 |
|
| Regulatory required programs | 35 |
| | (12 | ) |
| Transmission revenues | — |
| | 9 |
|
| Other | (3 | ) | | (15 | ) |
| Total increase | $ | 41 |
| | $ | 64 |
|
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
Volume, exclusive | | | | | | | | | | | | | |
| As of December 31, | | |
| Number of Electric Customers | 2020 | | 2019 | | |
| Residential | 832,190 | | | 817,770 | | | |
| Small commercial & industrial | 53,800 | | | 54,265 | | | |
| Large commercial & industrial | 22,459 | | | 22,271 | | | |
| Public authorities & electric railroads | 168 | | | 160 | | | |
| Total | 908,617 | | | 894,466 | | | |
Distribution Revenue increased for the year ended December 31, 20182020 compared to the same period in 2017, and for the year ended 2017 compared to the same period in 2016 primarily due to the impact of residential customer growth.
|
| | | | | | | | |
| | As of December 31, |
| Number of Electric Customers | 2018 | | 2017 | | 2016 |
| Residential | 807,442 |
| | 792,211 |
| | 780,652 |
|
| Small commercial & industrial | 54,306 |
| | 53,489 |
| | 53,529 |
|
| Large commercial & industrial | 22,022 |
| | 21,732 |
| | 21,391 |
|
| Public authorities & electric railroads | 150 |
| | 144 |
| | 130 |
|
| Total | 883,920 |
| | 867,576 |
| | 855,702 |
|
Distribution Revenues decreased for the year ended December 31, 2018 compared to the same period in 2017 primarily due to the impact of reduced distribution rates to reflect the lower federal income tax rate, partially offset by higher electric distribution rates in Maryland that became effective in October 2017 and June 2018 and higher electric distribution rates in the District of Columbia that became effective August 2017 and August 2018. Distribution revenues increased for the year ended December 31, 2017 compared to the same period in 2016,2019, primarily due to higher electric distribution rates in Maryland that became effective in November 2016August 2019 and October 2017 and higher electric distribution ratescustomer growth in the District of Columbia that became effective August 2017. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.Columbia.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG and SOS administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income. Revenues from regulatory required programs increased for the year ended December 31, 2018 compared to the same period in 2017 primarily due to increases in the Maryland and District of Columbia surcharge rates and sales due to higher volumes, as well as the DC PLUG surcharge which became effective in February 2018. Revenues from regulatory required programs decreased for the year ended December 31, 2017 compared to the same period
in 2016 primarily due to lower demand-side management program surcharge revenue due to a decrease in kWh sales and a rate decrease effective January 2017.
Transmission Revenues.Revenue. Under a FERC approvedFERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increaseddecreased for the year ended December 31, 20172020 compared to the same period in 20162019 primary due to higher rates effective June 2017.the settlement agreement of transmission-related income tax regulatory liabilities. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue Revenueincludes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes. Other revenue decreased for the year ended December 31, 20172020 compared to the same period in 2016 due2019, as Pepco temporarily suspended customer disconnections for non-payment beginning March of 2020 and temporarily ceased new late fees for all customers and restored services to lower pass-through revenue primarilycustomers upon request who were disconnected in the resultlast twelve months.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of lower salesthese programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that resultedchoose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a decrease in utility taxes that are collected by Pepco on behalf of the jurisdiction.slight mark-up.
See Note 245 - Segment Information forof the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The changes in Operating and maintenance expense consisteddecrease of the following:
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
| Baseline | | | |
ARO update(a) | $ | 22 |
| | $ | — |
|
Merger costs(b) | 13 |
| | (132 | ) |
BSC and PHISCO costs(c) | 9 |
| | (24 | ) |
| Uncollectible accounts expense | 2 |
| | (11 | ) |
| Labor, other benefits, contracting and materials | (2 | ) | | 15 |
|
Write-off of construction work in progress(d) | — |
| | (14 | ) |
Remeasurement of AMI-related regulatory asset(e) | — |
| | (7 | ) |
| Other | 4 |
| | (9 | ) |
| | 48 |
|
| (182 | ) |
| | | | |
| Regulatory required programs | (1 | ) | | (6 | ) |
| Total increase (decrease) | $ | 47 |
| | $ | (188 | ) |
__________
| |
(a) | Reflects an increase primarily related to asbestos identified at the Buzzard Point property. See Note 15 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
|
| |
(b) | Decrease in 2017 primarily due to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. Increase in 2018 primarily due to a deferral of accumulated merger integration costs as regulatory assets in 2017. |
| |
(c) | Decrease in 2017 primarily related to merger severance and compensation costs recognized in 2016. |
| |
(d) | Primarily resulting from a review of capital projects during the fourth quarter of 2016. |
| |
(e) | Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016. |
The changes in Depreciation and amortization expense consisted of the following:
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
Depreciation expense(a) | $ | 14 |
| | $ | 28 |
|
Regulatory asset amortization(b) | 25 |
| | 8 |
|
Regulatory required programs (c) | 25 |
| | (10 | ) |
| Total increase | $ | 64 |
| | $ | 26 |
|
_________
| |
(a) | Depreciation expense increased due to ongoing capital expenditures and higher depreciation rates in Maryland effective November 2016. |
| |
(b) | Regulatory asset amortization increased due to additional regulatory assets related to rate case activity. |
| |
(c) | Regulatory required programs increased as a result of higher amortization of the DC PLUG regulatory asset. |
Taxes other than income$63 million for the year ended December 31, 20182020 compared to the same period in 20172019, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | | |
| 2020 vs. 2019 | | |
| (Decrease) Increase | | |
| | | |
| | | |
| Change in environmental liabilities | $ | (22) | | | |
| Expiration of lease arrangement | (15) | | | |
| Pension and non-pension postretirement benefits expense | (6) | | | |
| BSC and PHISCO costs | (4) | | | |
| Storm related costs | (2) | | | |
Credit loss expense(a) | 8 | | | |
| Labor, other benefits, contracting, and materials | 15 | | | |
| | | |
| | | |
| Other | (1) | | | |
| (27) | | | |
| Regulatory required programs | (2) | | | |
| | | |
| Total decrease | $ | (29) | | | |
__________
(a)Increased credit loss expense primarily as a result of suspending customer disconnections, partially offset by the regulatory asset recorded in 2020 related to incremental credit loss expense due to COVID-19. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortizationexpense consisted of the following:
| | | | | | | |
| 2020 vs. 2019 | | |
| Increase (Decrease) | | |
Depreciation expense(a) | $ | 18 | | | |
| Regulatory asset amortization | (2) | | | |
| Regulatory required programs | (13) | | | |
| Total increase | $ | 3 | | | |
__________
(a)Depreciation and amortization increased primarily due to an increase in utility taxes that are collected and passed through by Pepco (which is substantially offset in Operating revenues). ongoing capital expenditures.
Taxes other than incomedecreased for the year ended December 31, 20172020 compared to the same period in 2016 decreased2019, primarily due to lower utility taxes as part of regulatory required programs that are collected and passed through by Pepco (which is substantiallyfully offset inwithin Operating revenues), partially offset by higher property taxes.revenues.
Gain on sales of assetsInterest expense, net increased for the year ended December 31, 20172020 compared to the same period in 2016 decreased2019, primarily due to the saleissuance of landdebt in May 2016.June 2019, February 2020, and June 2020.
Interest expense, netGain on sales of assets for the year ended December 31, 20182020 compared to the same period in 2017 increased primarily due to higher outstanding debt. Interest expense, net for the year ended December 31, 2017 compared to2019 increased due the same periodsale of land in 2016 decreased primarily due to the recordingfourth quarter of interest expense for an uncertain tax position in 2016, partially offset by higher outstanding debt.2020.
Other, net for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to the September 2016 reversal of contributions in aid of construction tax gross-up reserves due to the determination that there is no legal obligation to refund customers per contract term.
Effective income tax rates were (2.7)% and 6.2% for the years ended December 31, 2018, 2017,2020 and 2016 were 5.8%, 33.9%, and 49.4%,2019, respectively. The decrease inchange is primarily related to the effectivesettlement agreement of ongoing transmission-related income tax rate for the year ended December 31, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA.regulatory liabilities. See Note 3 — Regulatory Matters and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax ratesrates.
Results of Operations—DPL
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | (Unfavorable) Favorable Variance |
| Operating revenues | $ | 1,271 | | | $ | 1,306 | | | $ | (35) | |
| Operating expenses | | | | | |
| Purchased power and fuel expense | 503 | | | 526 | | | 23 | |
| Operating and maintenance | 361 | | | 323 | | | (38) | |
| Depreciation and amortization | 191 | | | 184 | | | (7) | |
| Taxes other than income taxes | 65 | | | 56 | | | (9) | |
| Total operating expenses | 1,120 | | | 1,089 | | | (31) | |
| | | | | |
| Operating income | 151 | | | 217 | | | (66) | |
| Other income and (deductions) | | | | | |
| Interest expense, net | (61) | | | (61) | | | — | |
| Other, net | 10 | | | 13 | | | (3) | |
| Total other income and (deductions) | (51) | | | (48) | | | (3) | |
| Income before income taxes | 100 | | | 169 | | | (69) | |
| Income taxes | (25) | | | 22 | | | 47 | |
| Net income | $ | 125 | | | $ | 147 | | | $ | (22) | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
| Operating revenues | $ | 1,332 |
| | $ | 1,300 |
| | $ | 32 |
| | $ | 1,277 |
| | $ | 23 |
|
| Purchased power and fuel expense | 561 |
| | 532 |
| | (29 | ) | | 583 |
| | 51 |
|
| Revenues net of purchased power and fuel expense | 771 |
| | 768 |
| | 3 |
| | 694 |
| | 74 |
|
| Other operating expenses | | | | | | | | |
|
|
| Operating and maintenance | 344 |
| | 315 |
| | (29 | ) | | 441 |
| | 126 |
|
| Depreciation and amortization | 182 |
| | 167 |
| | (15 | ) | | 157 |
| | (10 | ) |
| Taxes other than income | 56 |
| | 57 |
| | 1 |
| | 55 |
| | (2 | ) |
| Total other operating expenses | 582 |
| | 539 |
| | (43 | ) | | 653 |
| | 114 |
|
| Gain on sales of assets | 1 |
| | — |
| | 1 |
| | 9 |
| | (9 | ) |
| Operating income | 190 |
| | 229 |
| | (39 | ) | | 50 |
| | 179 |
|
| Other income and (deductions) | | | | | | | | |
|
|
| Interest expense, net | (58 | ) | | (51 | ) | | (7 | ) | | (50 | ) | | (1 | ) |
| Other, net | 10 |
| | 14 |
| | (4 | ) | | 13 |
| | 1 |
|
| Total other income and (deductions) | (48 | ) | | (37 | ) | | (11 | ) | | (37 | ) | | — |
|
| Income before income taxes | 142 |
| | 192 |
| | (50 | ) | | 13 |
| | 179 |
|
| Income taxes | 22 |
| | 71 |
| | 49 |
| | 22 |
| | (49 | ) |
| Net income (loss) | $ | 120 |
| | $ | 121 |
| | $ | (1 | ) | | $ | (9 | ) | | $ | 130 |
|
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017.2019.Net income remained relatively consistent. The TCJA did not significantly impact Net income as the favorable tax impacts were predominately offsetdecreased by lower revenues resulting from the pass back of the tax savings through customer rates.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.Net income increased $130$22 million primarily due to merger-relatedan increase in storm costs recognized in March 2016, higher distribution base ratesrelated to the August 2020 storms in Delaware, that became effective Julyan increase in credit loss expense primarily as a result of suspending customer disconnections partially offset by the regulatory asset recorded in 2020 related to incremental credit loss expense due to COVID-19, unfavorable weather conditions in DPL's Delaware electric service territory, and December 2016an increase in depreciation and higher distribution base rates in Maryland that became effective February 2017,amortization expense, partially offset by higher depreciation expense due to increased depreciationelectric distribution rates in Maryland effective February 2017. Income taxes expense included unrecognized tax benefits of $16 million for uncertain tax positions related to the deductibility of certain merger commitments in the first quarter of 2017. This decrease was offset byand an increase in income taxes due totransmission rates (net of the $6 million December 2017 impairmentimpact of certainthe settlement agreement of transmission-related income tax regulatory assets.liabilities).
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity and REC procurement costs and participation in customer choice programs. DPL recovers electricity and REC procurement costs from customers with a slight mark-up and natural gas costs from customers without mark-up. Therefore, fluctuations in these costs have minimal impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity.
The changes in RNFOperating revenues consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | |
| 2020 vs. 2019 | | |
| (Decrease) Increase | | |
| Electric | | Gas | | Total | | | | | | |
| Weather | $ | (9) | | | $ | — | | | $ | (9) | | | | | | | |
| Volume | 2 | | | (5) | | | (3) | | | | | | | |
| Distribution | 12 | | | 4 | | | 16 | | | | | | | |
| Transmission | (18) | | | — | | | (18) | | | | | | | |
| Other | 2 | | | (1) | | | 1 | | | | | | | |
| (11) | | | (2) | | | (13) | | | | | | | |
| Regulatory required programs | (17) | | | (5) | | | (22) | | | | | | | |
| Total decrease | $ | (28) | | | $ | (7) | | | $ | (35) | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 vs. 2017 | | 2017 vs. 2016 |
| | Increase (Decrease) | | Increase (Decrease) |
| | Electric | | Gas | | Total | | Electric | | Gas | | Total |
| Weather | $ | 11 |
| | $ | 8 |
| | $ | 19 |
| | $ | (7 | ) | | $ | (13 | ) | | $ | (20 | ) |
| Volume | 7 |
| | 2 |
| | 9 |
| | 2 |
| | 11 |
| | 13 |
|
| Distribution revenue | (20 | ) | | (6 | ) | | (26 | ) | | 65 |
| | 4 |
| | 69 |
|
| Regulatory required programs | (2 | ) | | (5 | ) | | (7 | ) | | (3 | ) | | — |
| | (3 | ) |
| Transmission revenues | 6 |
| | — |
| | 6 |
| | 10 |
| | — |
| | 10 |
|
| Other | 1 |
| | 1 |
| | 2 |
| | 6 |
| | (1 | ) | | 5 |
|
| Total increase | $ | 3 |
|
| $ | — |
|
| $ | 3 |
|
| $ | 73 |
|
| $ | 1 |
|
| $ | 74 |
|
Revenue Decoupling.The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution customers in Maryland are not affectedimpacted by unseasonably warmerabnormal weather or colder weather becauseusage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the year ended December 31, 20182020 compared to the same period in 2017, RNF2019, Operating revenues related to weather was higherdecreased primarily due to the impact of favorable weather conditions in DPL's Delaware service territory. During the year ended December 31, 2017 compared to the same period in 2016, RNF related to weather was lower due to the impact of unfavorable weather conditions in DPL's Delaware service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the yearsyear ended December 31, 2018 and December 31, 20172020 compared to same periodsperiod in 2017 and 2016, respectively,2019 and normal weather consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | | | % Change |
| Delaware Electric Service Territory | 2020 | | 2019 | | Normal | | 2020 vs. 2019 | | 2020 vs. Normal |
| Heating Degree-Days | 4,146 | | | 4,475 | | | 4,652 | | | (7.4) | % | | (10.9) | % |
| Cooling Degree-Days | 1,264 | | | 1,476 | | | 1,239 | | | (14.4) | % | | 2.0 | % |
| | | | | | | | | |
| | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| Delaware Electric Service Territory | For the Years Ended December 31, | | | | % Change |
| Heating and Cooling Degree-Days | 2018 | | 2017 | | Normal | | 2018 vs. 2017 | | 2018 vs. Normal |
| Heating Degree-Days | 4,713 |
| | 4,203 |
| | 4,624 |
| | 12.1 | % | | 1.9 | % |
| Cooling Degree-Days | 1,456 |
| | 1,265 |
| | 1,210 |
| | 15.1 | % | | 20.3 | % |
| | | | | | | | | | |
| | For the Years Ended December 31, | | | | % Change |
| Heating and Cooling Degree-Days | 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal |
| Heating Degree-Days | 4,203 |
| | 4,454 |
| | 4,664 |
| | (5.6 | )% | | (9.9 | )% |
| Cooling Degree-Days | 1,265 |
| | 1,463 |
| | 1,193 |
| | (13.5 | )% | | 6.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | | | % Change |
| Delaware Natural Gas Service Territory | 2020 | | 2019 | | Normal | | 2020 vs. 2019 | | 2020 vs. Normal |
| Heating Degree-Days | 4,146 | | | 4,475 | | | 4,675 | | | (7.4) | % | | (11.3) | % |
| | | | | | | | | |
| | | | | |
| | | | | | | | | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| Delaware Natural Gas Service Territory | For the Years Ended December 31, | | | | % Change |
| Heating Degree-Days | 2018 | | 2017 | | Normal | | 2018 vs. 2017 | | 2018 vs. Normal |
| Heating Degree-Days | 4,713 |
| | 4,203 |
| | 4,716 |
| | 12.1 | % | | (0.1 | )% |
| | | | | | | | | | |
| | For the Years Ended December 31, | | | | % Change |
| Heating Degree-Days | 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal |
| Heating Degree-Days | 4,203 |
| | 4,454 |
| | 4,739 |
| | (5.6 | )% | | (11.3 | )% |
Volume, exclusive of the effects of weather, remained relatively consistent for the year ended December 31, 2020 compared to the same period in 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Retail Deliveries to Delaware Customers (in GWhs) | 2020 | | 2019 | | % Change 2020 vs. 2019 | | Weather - Normal % Change (b) | | | | | | |
| Residential | 3,149 | | | 3,149 | | | — | % | | 4.8 | % | | | | | | |
| Small commercial & industrial | 1,255 | | | 1,320 | | | (4.9) | % | | (2.6) | % | | | | | | |
| Large commercial & industrial | 3,225 | | | 3,424 | | | (5.8) | % | | (4.8) | % | | | | | | |
| Public authorities & electric railroads | 32 | | | 34 | | | (5.9) | % | | (5.9) | % | | | | | | |
Total electric retail deliveries(a) | 7,661 | | | 7,927 | | | (3.4) | % | | (0.7) | % | | | | | | |
| | | | | | | | | | | | | |
| As of December 31, | | |
| Number of Total Electric Customers (Maryland and Delaware) | 2020 | | 2019 | | |
| Residential | 472,621 | | | 468,162 | | | |
| Small commercial & industrial | 62,461 | | | 61,721 | | | |
| Large commercial & industrial | 1,223 | | | 1,411 | | | |
| Public authorities & electric railroads | 609 | | | 613 | | | |
| Total | 536,914 | | | 531,907 | | | |
__________
(a)Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas Retail Deliveries to Delaware Customers (in mmcf) | 2020 | | 2019 | | % Change 2020 vs. 2019 | | Weather - Normal % Change(b) | | | | | | |
| Residential | 7,832 | | | 8,613 | | | (9.1) | % | | (2.5) | % | | | | | | |
| Small commercial & industrial | 3,718 | | | 4,287 | | | (13.3) | % | | (7.5) | % | | | | | | |
| Large commercial & industrial | 1,703 | | | 1,811 | | | (6.0) | % | | (6.0) | % | | | | | | |
| Transportation | 6,631 | | | 6,733 | | | (1.5) | % | | 0.2 | % | | | | | | |
Total natural gas deliveries(a) | 19,884 | | | 21,444 | | | (7.3) | % | | (3.0) | % | | | | | | |
| | | | | | | | | | | | | |
| As of December 31, | | |
| Number of Delaware Natural Gas Customers | 2020 | | 2019 | | |
| Residential | 127,128 | | | 125,873 | | | |
| Small commercial & industrial | 10,017 | | | 9,999 | | | |
| Large commercial & industrial | 16 | | | 17 | | | |
| Transportation | 161 | | | 159 | | | |
| Total | 137,322 | | | 136,048 | | | |
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Distribution Revenue increased for the year ended December 31, 20182020 compared to the same period in 2017 primarily due to the impact of increased average residential customer usage in DPL's Delaware service territory and overall customer growth. Volume increased for the year ended December 31, 2017 compared to the same period in 2016, primarily due to the impact of customer growth.
|
| | | | | | | | | | | | | | | | | | | | |
| Electric Retail Deliveries to Delaware Customers (in GWhs) | 2018 | | 2017 | | % Change 2018 vs. 2017 | | Weather - Normal % Change | | 2016 | | % Change 2017 vs. 2016 | | Weather - Normal % Change |
| Retail Deliveries | | | | | | | | | | | | | |
| Residential | 3,204 |
| | 2,967 |
| | 8.0 | % | | 1.8 | % | | 3,072 |
| | (3.4 | )% | | 0.9 | % |
| Small commercial & industrial | 1,344 |
| | 1,317 |
| | 2.1 | % | | — | % | | 1,341 |
| | (1.8 | )% | | (0.2 | )% |
| Large commercial & industrial | 3,636 |
| | 3,473 |
| | 4.7 | % | | 3.7 | % | | 3,476 |
| | (0.1 | )% | | 0.9 | % |
| Public authorities & electric railroads | 33 |
| | 32 |
| | 3.1 | % | | 3.4 | % | | 35 |
| | (8.6 | )% | | (7.1 | )% |
Total electric retail deliveries(a) | 8,217 |
| | 7,789 |
| | 5.5 | % | | 2.3 | % | | 7,924 |
| | (1.7 | )% | | 0.7 | % |
__________
| |
(a) | Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. |
|
| | | | | | | | |
| | As of December 31, |
| Number of Total Electric Customers (Maryland and Delaware) | 2018 | | 2017 | | 2016 |
| Residential | 463,670 |
| | 459,389 |
| | 456,181 |
|
| Small commercial & industrial | 61,381 |
| | 60,697 |
| | 60,173 |
|
| Large commercial & industrial | 1,406 |
| | 1,400 |
| | 1,411 |
|
| Public authorities & electric railroads | 621 |
| | 629 |
| | 643 |
|
| Total | 527,078 |
| | 522,115 |
| | 518,408 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| Natural Gas Retail Deliveries to Delaware Customers (in mmcf) | 2018 | | 2017 | | % Change 2018 vs. 2017 | | Weather Normal % change | | 2016 | | % Change 2017 vs. 2016 | | Weather Normal % change |
| Retail Deliveries | | | | | | | | | | | | | |
| Residential | 8,633 |
| | 7,445 |
| | 16.0 | % | | 3.4 | % | | 7,765 |
| | (4.1 | )% | | 1.1 | % |
| Small commercial & industrial | 4,134 |
| | 3,754 |
| | 10.1 | % | | (1.6 | )% | | 3,700 |
| | 1.5 | % | | 6.5 | % |
| Large commercial & industrial | 1,952 |
| | 1,908 |
| | 2.3 | % | | 2.3 | % | | 1,875 |
| | 1.8 | % | | 1.7 | % |
| Transportation | 6,831 |
| | 6,538 |
| | 4.5 | % | | 2.3 | % | | 6,202 |
| | 5.4 | % | | 6.3 | % |
Total natural gas deliveries(a) | 21,550 |
| | 19,645 |
| | 9.7 | % | | 2.0 | % | | 19,542 |
| | 0.5 | % | | 3.8 | % |
_________
| |
(a) | Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. |
|
| | | | | | | | |
| | As of December 31, |
| Number of Delaware Gas Customers | 2018 | | 2017 | | 2016 |
| Residential | 124,183 |
| | 122,347 |
| | 120,951 |
|
| Small commercial & industrial | 9,986 |
| | 9,833 |
| | 9,784 |
|
| Large commercial & industrial | 18 |
| | 20 |
| | 17 |
|
| Transportation | 156 |
| | 154 |
| | 156 |
|
| Total | 134,343 |
| | 132,354 |
| | 130,908 |
|
Distribution Revenue decreased for the year ended December 31, 2018 compared to the same period in 2017 primarily due to reduced electric distribution rates and gas distribution rates in Delaware that were put into effect in March 2018 which reflect the impact of the lower federal income tax rate. Distribution revenue increased for the year ended December 31, 2017 compared to the same period in 2016,2019 primarily due to higher electric distribution rates in Maryland that became effective in July 2020, higher electric and natural gas distribution base rates in Delaware that became effective in Julythe second half of 2020, and December 2016 and higher electric distribution base rates in Maryland that became effective in February 2017. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.Distribution System Improvement Charge (DSIC) rate increases during 2020.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS administrative costs and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.
Transmission Revenues.Revenue. Under a FERC approvedFERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar years. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increaseddecreased for the year ended December 31, 20182020 compared to the same period in 2017 and for the year ended 2017 compared2019 primarily due to the same period in 2016 duesettlement agreement of transmission-related income tax regulatory liabilities, partially offset by higher fully recoverable costs. See Note 3 — Regulatory Matters of the Combined Notes to higher rates effective June 2018 and June 2017.Consolidated Financial Statements for additional information.
Other revenue Revenueincludes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up and natural gas costs without mark-up.
See Note 245 - Segment Information forof the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The changes in Operating and maintenance expense consisteddecrease of the following:
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
| Baseline | | | |
Merger costs(a) | $ | 7 |
| | $ | (94 | ) |
Energy efficiency merger commitments customer credits(b) | 5 |
| | — |
|
BSC and PHISCO costs(c) | 4 |
| | (15 | ) |
| Labor, other benefits, contracting and materials | 4 |
| | 8 |
|
Write-off of construction work in progress(d) | 3 |
| | (3 | ) |
| Uncollectible accounts expense | 1 |
| | (10 | ) |
| Other | 6 |
| | (5 | ) |
| | 30 |
|
| (119 | ) |
| | | | |
| Regulatory required programs | (1 | ) | | (7 | ) |
| Total increase (decrease) | $ | 29 |
| | $ | (126 | ) |
_________
| |
(a) | Decrease in 2017 primarily due to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. Increase in 2018 primarily due to a deferral of accumulated merger integration costs as regulatory assets in 2017. |
| |
(b) | Related to EmPower Maryland energy efficiency customer credits. |
| |
(c) | Decrease in 2017 primarily related to merger severance and compensation costs recognized in 2016. |
| |
(d) | Decrease in 2017 primarily related to a review of capital projects in 2016. |
The changes in Depreciation and amortization expense consisted of the following:
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
Depreciation expense(a) | $ | 6 |
| | $ | 14 |
|
Regulatory asset amortization (b) | 18 |
| | — |
|
Regulatory required programs(c) | (9 | ) | | (4 | ) |
| Total increase | $ | 15 |
| | $ | 10 |
|
_________
| |
(a) | Depreciation expense increased due to ongoing capital expenditures and higher depreciation rates in Maryland effective February 2017. |
| |
(b) | Regulatory asset amortization increased due to additional regulatory assets related to rate case activity. |
| |
(c) | Regulatory required programs decreased primarily due to an EmPower Maryland surcharge rate decrease effective January 2018 and 2017. |
Gain on sales of assets$23 million for the year ended December 31, 20172020 compared to the same period in 2016 decreased2019, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | | |
| 2020 vs. 2019 | | |
| Increase
(Decrease) | | |
| Storm-related costs | $ | 19 | | | |
| Labor, other benefits, contracting, and materials | 14 | | | |
| | | |
| | | |
Credit loss expense(a) | 8 | | | |
| Pension and non-pension postretirement benefits expense | (4) | | | |
| BSC and PHISCO costs | (1) | | | |
| Other | (1) | | | |
| 35 | | | |
| Regulatory required programs | 3 | | | |
| Total increase | $ | 38 | | | |
__________
(a)Increased credit loss expense primarily as a result of suspending customer disconnections, partially offset by the regulatory asset recorded in 2020 related to incremental credit loss expense due to COVID-19. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:
| | | | | | | |
| 2020 vs. 2019 | | |
| Increase
(Decrease) | | |
Depreciation and amortization(a) | $ | 10 | | | |
| Regulatory asset amortization | (1) | | | |
| Regulatory required programs | (2) | | | |
| Total increase | $ | 7 | | | |
__________
(a)Depreciation and amortization increased primarily due to the sale of land in July and December 2016.ongoing capital expenditures.
Interest expense, netTaxes other than income taxesincreased for the year ended December 31, 20182020 compared to the same period in 2017 increased2019 primarily due to higher outstanding debt.property taxes for Maryland and Delaware.
Other, netEffective income tax rates were (25.0)% and 13.0% for the years ended December 31, 2020 and 2019, respectively. The decrease for the year ended December 31, 2018 compared2020 is primarily related to the same period in 2017 decreased primarily due to lower income from AFUDC equity.
Effectivesettlement agreement of transmission-related income tax rates for the years ended December 31, 2018, 2017regulatory liabilities. See Note 3 — Regulatory Matters and 2016 were 15.5%, 37.0% and 169.2%, respectively. The decrease in the effective income tax rate for the year ended December 31, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax ratesrates.
Results of Operations—ACE
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | Favorable
(Unfavorable) Variance |
| Operating revenues | $ | 1,245 | | | $ | 1,240 | | | $ | 5 | |
| Operating expenses | | | | | |
| Purchased power expense | 609 | | | 608 | | | (1) | |
| Operating and maintenance | 326 | | | 320 | | | (6) | |
| Depreciation and amortization | 180 | | | 157 | | | (23) | |
| Taxes other than income taxes | 8 | | | 4 | | | (4) | |
| Total operating expenses | 1,123 | | | 1,089 | | | (34) | |
| Gain on sale of assets | 2 | | | — | | | 2 | |
| Operating income | 124 | | | 151 | | | (27) | |
| Other income and (deductions) | | | | | |
| Interest expense, net | (59) | | | (58) | | | (1) | |
| Other, net | 6 | | | 6 | | | — | |
| Total other income and (deductions) | (53) | | | (52) | | | (1) | |
| Income before income taxes | 71 | | | 99 | | | (28) | |
| Income taxes | (41) | | | — | | | 41 | |
| Net income | $ | 112 | | | $ | 99 | | | $ | 13 | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
| Operating revenues | $ | 1,236 |
| | $ | 1,186 |
| | $ | 50 |
| | $ | 1,257 |
| | $ | (71 | ) |
| Purchased power expense | 616 |
| | 570 |
| | (46 | ) | | 651 |
| | 81 |
|
| Revenues net of purchased power expense | 620 |
| | 616 |
| | 4 |
| | 606 |
| | 10 |
|
| Other operating expenses | | | | |
| | | |
|
| Operating and maintenance | 330 |
| | 307 |
| | (23 | ) | | 428 |
| | 121 |
|
| Depreciation and amortization | 136 |
| | 146 |
| | 10 |
| | 165 |
| | 19 |
|
| Taxes other than income | 5 |
| | 6 |
| | 1 |
| | 7 |
| | 1 |
|
| Total other operating expenses | 471 |
| | 459 |
| | (12 | ) | | 600 |
| | 141 |
|
| Gain on sales of assets | — |
| | — |
| | — |
| | 1 |
| | (1 | ) |
| Operating income | 149 |
| | 157 |
| | (8 | ) | | 7 |
| | 150 |
|
| Other income and (deductions) | | | | |
| | | |
|
| Interest expense, net | (64 | ) | | (61 | ) | | (3 | ) | | (62 | ) | | 1 |
|
| Other, net | 2 |
| | 7 |
| | (5 | ) | | 9 |
| | (2 | ) |
Total other income and (deductions) | (62 | ) | | (54 | ) | | (8 | ) | | (53 | ) | | (1 | ) |
| Income (loss) before income taxes | 87 |
| | 103 |
| | (16 | ) | | (46 | ) | | 149 |
|
| Income taxes | 12 |
| | 26 |
| | 14 |
| | (4 | ) | | (30 | ) |
| Net income (loss) | $ | 75 |
| | $ | 77 |
| | $ | (2 | ) | | $ | (42 | ) | | $ | 119 |
|
Year Ended December 31, 20182020 Compared to Year Ended December 31, 20172019. Net income remained relatively consistent. The TCJA did not significantly impact Net income as the favorable income tax impacts were predominately offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. Net Incomeincreased by $119$13 million primarily due to merger-related costs recognized in March 2016 and higher electric distribution base rates effective August 2016 and October 2017 and an increase in transmission formula rate revenues,rates (net of the impact of the settlement agreement of transmission-related income tax regulatory liabilities), partially offset by lower customer usage. Income taxes expense included unrecognized tax benefits of $22 million for uncertain tax positions related to the deductibility of certain merger commitments in the first quarter of 2017. This decrease was offset by an increase in income taxes due to the December 2017 impairment of certain transmission-related income tax regulatory assets of $7 million.depreciation and amortization expense and unfavorable weather conditions in ACE's service territory.
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity and REC procurement costs and participation in customer choice programs. ACE recovers electricity and REC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs of supplier do not impact the volume of deliveries or RNF, but impact revenues related to supplied electricity.
The changes in RNF,Operating revenues consisted of the following:
| | | | | | | |
| 2020 vs. 2019 | | |
| (Decrease) Increase | | |
| Weather | $ | (8) | | | |
| Volume | (1) | | | |
| Distribution | 24 | | | |
| | | |
| Transmission | (19) | | | |
| | | |
| | | |
| | | |
| Other | 3 | | | |
| (1) | | | |
| Regulatory required programs | 6 | | | |
| Total increase | $ | 5 | | | |
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
| Weather | $ | 12 |
| | $ | (3 | ) |
| Volume | 14 |
| | (20 | ) |
| Distribution revenue | 2 |
| | 40 |
|
| Regulatory required programs | (23 | ) | | (24 | ) |
| Transmission revenues | (4 | ) | | 22 |
|
| Other | 3 |
| | (5 | ) |
| Total increase | $ | 4 |
| | $ | 10 |
|
Weather. The demand for electricity is affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. DuringThere was a decrease related to weather for the year ended December 31, 20182020 compared to the same period in 2017, RNF related to weather was higher due to the impact of favorable weather conditions in ACE's service territory. During the year ended December 31, 2017 compared to the same period in 2016, RNF related to weather was lower2019 due to the impact of unfavorable winter weather conditions.conditions in ACE's service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the yearsyear ended December 31, 2018 and December 31, 20172020 compared to same periodsperiod in 2017 and 2016, respectively,2019, and normal weather consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | Normal | | % Change |
| Heating and Cooling Degree-Days | 2020 | | 2019 | | | 2020 vs. 2019 | | 2020 vs. Normal |
| Heating Degree-Days | 4,029 | | | 4,467 | | | 4,667 | | | (9.8) | % | | (13.7) | % |
| Cooling Degree-Days | 1,314 | | | 1,374 | | | 1,174 | | | (4.4) | % | | 11.9 | % |
| | | | | | | | | |
| | | | | |
| | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | |
| | For the Years Ended December 31, | | Normal | | % Change |
| Heating and Cooling Degree-Days | 2018 | | 2017 | | | 2018 vs. 2017 | | 2018 vs. Normal |
| Heating Degree-Days | 4,523 |
| | 4,206 |
| | 4,666 |
| | 7.5 | % | | (3.1 | )% |
| Cooling Degree-Days | 1,535 |
| | 1,228 |
| | 1,135 |
| | 25.0 | % | | 35.2 | % |
| | | | | | | | | | |
| | For the Years Ended December 31, | | Normal | | % Change |
| Heating and Cooling Degree-Days | 2017 | | 2016 | | | 2017 vs. 2016 | | 2017 vs. Normal |
| Heating Degree-Days | 4,206 |
| | 4,487 |
| | 4,713 |
| | (6.3 | )% | | (10.8 | )% |
| Cooling Degree-Days | 1,228 |
| | 1,303 |
| | 1,115 |
| | (5.8 | )% | | 10.1 | % |
Volume,exclusive of the effects of weather, remained relatively consistent for the year ended December 31, 2020 compared to the same period in 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Retail Deliveries to Customers (in GWhs) | 2020 | | 2019 | | % Change 2020 vs. 2019 | | Weather - Normal % Change(b) | | | | | | |
| Residential | 4,029 | | | 3,966 | | | 1.6 | % | | 4.7 | % | | | | | | |
| Small commercial & industrial | 1,277 | | | 1,346 | | | (5.1) | % | | (4.0) | % | | | | | | |
| Large commercial & industrial | 3,067 | | | 3,429 | | | (10.6) | % | | (10.0) | % | | | | | | |
| Public authorities & electric railroads | 47 | | | 47 | | | — | % | | (0.2) | % | | | | | | |
Total retail deliveries(a) | 8,420 | | | 8,788 | | | (4.2) | % | | (2.5) | % | | | | | | |
| | | | | | | | | | | | | |
| As of December 31, | | |
| Number of Electric Customers | 2020 | | 2019 | | |
| Residential | 497,672 | | | 494,596 | | | |
| Small commercial & industrial | 61,622 | | | 61,497 | | | |
| Large commercial & industrial | 3,282 | | | 3,392 | | | |
| Public authorities & electric railroads | 701 | | | 679 | | | |
| Total | 563,277 | | | 560,164 | | | |
__________
(a)Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
Distribution Revenue increased for the year ended December 31, 20182020 compared to the same period in 2017, primarily due to higher average residential and commercial usage. Volume, exclusive of the effects of weather, decreased for the year ended December 31, 2017 compared to the same period in 2016, primarily due to lower average customer usage, partially offset by the impact of customer growth.
|
| | | | | | | | | | | | | | | | | | | | |
| Electric Retail Deliveries to Customers (in GWhs) | 2018 | | 2017 | | % Change 2018 vs. 2017 | | Weather - Normal % Change | | 2016 | | % Change 2017 vs. 2016 | | Weather - Normal % Change |
Retail Deliveries(a) | | | | | | | | | | | | | |
| Residential | 4,185 |
| | 3,853 |
| | 8.6 | % | | 4.0 | % | | 4,153 |
| | (7.2 | )% | | (6.2 | )% |
| Small commercial & industrial | 1,361 |
| | 1,286 |
| | 5.8 | % | | 3.5 | % | | 1,455 |
| | (11.6 | )% | | (11.1 | )% |
| Large commercial & industrial | 3,565 |
| | 3,399 |
| | 4.9 | % | | 3.7 | % | | 3,402 |
| | (0.1 | )% | | 0.4 | % |
| Public authorities & electric railroads | 49 |
| | 47 |
| | 4.3 | % | | 4.5 | % | | 49 |
| | (4.1 | )% | | (4.1 | )% |
| Total retail deliveries | 9,160 |
| | 8,585 |
| | 6.7 | % | | 3.8 | % | | 9,059 |
| | (5.2 | )% | | (4.5 | )% |
|
| | | | | | | | |
| | As of December 31, |
| Number of Electric Customers | 2018 | | 2017 | | 2016 |
| Residential | 490,975 |
| | 487,168 |
| | 484,240 |
|
| Small commercial & industrial | 61,386 |
| | 61,013 |
| | 61,008 |
|
| Large commercial & industrial | 3,515 |
| | 3,684 |
| | 3,763 |
|
| Public authorities & electric railroads | 656 |
| | 636 |
| | 610 |
|
| Total | 556,532 |
| | 552,501 |
| | 549,621 |
|
__________
| |
(a) | Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. |
Distribution Revenue increased for the year ended December 31, 2018 compared to the same period in 20172019 primarily due to higher electric distribution base rates that became effective in November 2017, partially offset by the impact of reduced distribution rates to reflect the lower federal income tax rate. Distribution revenue increased for the year ended December 31, 2017 compared to the same period in 2016, primarily due to higher electric distribution base rates that became effective in August 2016April 2019 and October 2017. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.April 2020.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds and BGS administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income. Revenues from regulatory programs decreased for the year ended December 31, 2018 compared to the same period in 2017, and for the year ended 2017 compared to the same period in 2016 due to rate decreases effective October 2017 and 2016 respectively for the ACE Transition Bonds.
Transmission Revenues. Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased for the year ended December 31, 20182020 compared to the same period in 20172019 primarily due to the impactsettlement agreement for transmission-related income tax regulatory liabilities, partially offset by higher fully recoverable costs. See Note 3 — Regulatory Matters of the lower federal income tax rate. Transmission revenue increasedCombined Notes to Consolidated Financial Statements for the year ended December 31, 2017 compared to the same period in 2016 due to higher rates effective June 2017 and June 2016 related to increases in transmission plant investment and operating expenses.additional information.
Other revenue Revenueincludes rental revenue, revenueservice connection fees, and mutual assistance revenues.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers.
Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore does not record Operating revenues or Purchased power expense related to late payment charges, mutual assistancethe electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and recoveries of other taxes.Purchased power expense related to the electricity, ZECs, and RECs.
See Note 245 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The changes in Operating and maintenance expense consistedincrease of the following:
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
| Baseline | | | |
| Labor, other benefits, contracting and materials | $ | 17 |
| | $ | 9 |
|
BSC and PHISCO costs(a) | 10 |
| | (11 | ) |
Merger costs(b) | 7 |
| | (120 | ) |
Uncollectible accounts expense(c) | (8 | ) | | — |
|
| Other | (2 | ) | | 1 |
|
| | 24 |
| | (121 | ) |
| | | | |
| Regulatory required programs | (1 | ) | | — |
|
| Total increase (decrease) | $ | 23 |
| | $ | (121 | ) |
_________
| |
(a) | Decrease in 2017 primarily related to merger severance and compensation costs recognized in 2016. |
| |
(b) | Decrease in 2017 primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. Increase in 2018 primarily related to a deferral of accumulated merger integration costs as regulatory assets in 2017. |
| |
(c) | ACE is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. An equal and offsetting amount has been recognized in Operating revenues for the periods presented. |
The changes in Depreciation and amortizationexpense consisted of the following:
|
| | | | | | | |
| | Increase (Decrease)
2018 vs. 2017 | | Increase (Decrease)
2017 vs. 2016 |
Depreciation expense(a) | $ | 5 |
| | $ | 6 |
|
Regulatory asset amortization(b) | 5 |
| | (2 | ) |
Required regulatory programs(c) | (20 | ) | | (24 | ) |
| Other | — |
| | 1 |
|
| Total decrease | $ | (10 | ) | | $ | (19 | ) |
_________
| |
(a) | Depreciation expense increased due to ongoing capital expenditures. |
| |
(b) | Regulatory asset amortization increased due to additional regulatory assets related to rate case activity. |
| |
(c) | Regulatory required programs decreased due to rate decreases effective October 2017 and 2016 respectively for the ACE Transition Bonds. |
Other, net $1 million for the year ended December 31, 20182020 compared to the same period in 2017 decreased2019, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
| | | | | | | |
| 2020 vs. 2019 | | |
| Increase (Decrease) | | |
| Labor, other benefits, contracting and materials | $ | 6 | | | |
| Storm-related costs | 3 | | | |
| | | |
| Pension and non-pension postretirement benefits expense | (1) | | | |
| | | |
| | | |
| Other | (2) | | | |
| 6 | | | |
Regulatory required programs(a) | — | | | |
| Total increase | $ | 6 | | | |
| | | |
| | | |
| | | |
__________
(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge.
The changes in Depreciation and amortizationexpense consisted of the following:
| | | | | | | |
| 2020 vs. 2019 | | |
| Increase (Decrease) | | |
Depreciation and amortization(a) | $ | 17 | | | |
| Regulatory asset amortization | (2) | | | |
| Regulatory required programs | 8 | | | |
| | | |
| Total increase | $ | 23 | | | |
__________
(a)Depreciation and amortization increased primarily due to lower income from AFUDC equity.ongoing capital expenditures.
Gain on sale of assets for year ended December 31, 2020 compared to same period in 2019 increased due to the sale of land in the first quarter of 2020.
Effective income tax rates were 13.8%, 25.2%,(57.7)% and 8.7%0.0% for the years ended December 31, 2018, 20172020 and 2016,2019, respectively. The decrease for the year ended December 31, 2018 comparedchange is primarily related to the same period in 2017 primarily due to the lower federalsettlement agreement of transmission-related income tax rate as a result of the TCJA.regulatory liabilities. See Note 3 — Regulatory Matters and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
Liquidity and Capital Resources
Exelon activity presented below includes the activity of PHI, Pepco, DPL and ACE, from the PHI Merger effective date of March 24, 2016 through December 31, 2018. Exelon prior year activity is unadjusted for the effects of the
PHI Merger. Due to the application of push-down accounting to the PHI entity, PHI's activity is presented in two separate reporting periods, the legacy PHI activity through March 23, 2016 (Predecessor), and PHI activity for the remainder of the period after the PHI merger date (Successor). For each of Pepco, DPL and ACE the activity presented below include its activity for the years ended December 31, 2018, 2017 and 2016. All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, the sale of certain receivables, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices,
and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to unsecured revolving credit facilities with aggregate bank commitments of $9$10.6 billion. In addition,As a result of disruptions in the commercial paper markets due to COVID-19 in March of 2020, Generation has $545 millionborrowed $1.5 billion on its revolving credit facility to refinance commercial paper. Generation repaid the $1.5 billion borrowed on the revolving credit facility on April 3, 2020 using funds from short-term loans issued in bilateral facilities with banks which have various expirations between October 2019March 2020, cash proceeds from the sale of certain customer accounts receivable, and April 2021 and $159 in credit facilitiesborrowings from the Exelon intercompany money pool. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for project finance.additional information on the sale of customer accounts receivable. See Executive Overview for additional information on COVID-19. The Registrants continue to utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements.
The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefitOPEB obligations, and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd, PECO, BGE, Pepco, DPL and ACEthe Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 1317 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt and credit agreements.
Despite disruptions in the financial markets due to COVID-19, the Registrants issued long-term debt of $5.3 billion and were able to successfully complete their planned long-term debt issuances in 2020.
NRC Minimum Funding Requirements (Exelon and Generation)
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are typically based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 1510 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information on the NRC minimum funding requirements.information.
If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT funds could appreciate in value. A shortfall could require that Generation address the shortfall by, among other things, obtaining a parental guarantee for Generation’s share of the funding assurance. However, the amount of any guarantees or other assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. Within two years after shutting down a plant, Generation must submit a post-shutdown decommissioning activities report (PSDAR)PSDAR to the NRC that includes the planned option for decommissioning the site. As discussedUpon retirement, Dresden will have adequate funding assurance, however, due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in Note 15 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements, Generation filed its annual decommissioning funding status report withvalue, Byron may no longer meet the NRC on March 28, 2018 for shutdown reactorsminimum funding requirements and, reactors within five years of shutdown. As of December 31, 2018, acrossas a result, the alternative decommissioning approaches available, Exelon would not be required to postNRC may require additional financial assurance including possibly a parental guarantee from Exelon. Considering the different approaches to decommissioning available to Generation, the most likely estimates currently anticipated could require financial assurance for TMI or Oyster Creek. In the event PSEG decides to early retire Salem, Generation estimates a parental guaranteeradiological decommissioning at Byron of up to $30 million from Exelon could be required for Salem, dependent upon the ultimate decommissioning approach selected.$90 million.
Upon issuance of any required financial guarantees, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, under the regulations, the NRC must approve an additional exemption in order for the plant’s owner(s)Generation to utilize the NDT fundfunds to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs)costs, if applicable). If a unit does not receive this exemption, thethose costs would be borne by Generation without reimbursement from or access to the owner(s).NDT funds. Accordingly, based on current projections of the most likely decommissioning approach, it is expected that Dresden would not require supplemental cash from Generation, but some portion of the Byron spent fuel management costs would need to be funded through supplemental cash from Generation. While the ultimate amounts may vary
greatly and could be reducedoffset by alternate decommissioning scenarios and/or reimbursement of certain spent fuel management costs under the DOE reimbursement agreements or future litigation, across the alternativesettlement agreement, decommissioning approaches available, if TMI were to fail to obtain the exemption,for Byron may require supplemental cash from Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $125$185 million, net of taxes, dependent uponover a period of 10 years after permanent shutdown.
As of December 31, 2020, Exelon would not be required to post a parental guarantee for TMI Unit 1 under the ultimateSAFSTOR scenario which is the planned decommissioning approach selected. Inoption as described in the event PSEG decides to early retire Salem and Salem were to fail to obtainTMI Unit 1 PSDAR filed by Generation with the exemption, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $90 million net of taxes.NRC on April 5, 2019. On October 19, 2018,16, 2019, the NRC granted Generation's exemption request to use the Oyster CreekTMI Unit 1 NDT funds for non-radiological decommissioningspent fuel management costs.
On July 31, 2018, Generation entered into an agreement for An additional exemption request would be required to allow the sale of Oyster Creekfunds to be spent on site restoration costs, which isare not expected to occurbe incurred in the second halfnear term.
Project Financing (Exelon and Generation)
Project financing is used to help mitigate risk of 2019.specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project finance has credit facilities. See Note 5 - Mergers, Acquisitions17 — Debt and Dispositions for additional information on the sale of Oyster Creek to Holtec.
Junior Subordinated Notes
In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earnings as of December 31, 2017. See Note 20 — Earnings Per ShareCredit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the issuance of common stock.nonrecourse debt and credit facilities.
Cash Flows from Operating Activities
General (All Registrants)
Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers.
The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, competitive suppliers, and their ability to achieve operating cost reductions.
See Note 43 — Regulatory Matters and Note 2219 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of regulatory and legal proceedings and proposed legislation.
The following table provides a summary of the major items affecting Exelon’schange in cash flows from operationsoperating activities for the years ended December 31, 2018, 20172020 and 2016:2019 by Registrant:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Decrease) increase in cash flows from operating activities | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Net income | $ | (1,074) | | | $ | (638) | | | $ | (250) | | | $ | (81) | | | $ | (11) | | | $ | 18 | | | $ | 23 | | | $ | (22) | | | $ | 13 | |
| Adjustments to reconcile net income to cash: | | | | | | | | | | | | | | | | | |
| Non-cash operating activities | 273 | | | 328 | | | 156 | | | (42) | | | (33) | | | (120) | | | (123) | | | 25 | | | (3) | |
| Pension and non-pension postretirement benefit contributions | (193) | | | (80) | | | (71) | | | 10 | | | (30) | | | (14) | | | 3 | | | 1 | | | (1) | |
| Income taxes | 204 | | | (116) | | | (87) | | | 65 | | | 127 | | | (41) | | | (10) | | | (37) | | | (3) | |
| Changes in working capital and other noncurrent assets and liabilities | (2,456) | | | (2,633) | | | (93) | | | 74 | | | 79 | | | 42 | | | 96 | | | 11 | | | (68) | |
| Option premiums paid, net | (110) | | | (110) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Collateral received (posted), net | 932 | | | 960 | | | (34) | | | — | | | 4 | | | — | | | — | | | — | | | — | |
| (Decrease) increase in cash flows from operating activities | $ | (2,424) | | | $ | (2,289) | | | $ | (379) | | | $ | 26 | | | $ | 136 | | | $ | (115) | | | $ | (11) | | | $ | (22) | | | $ | (62) | |
|
| | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2018 vs. 2017 Variance | | 2016 | | 2017 vs. 2016 Variance |
| Net income | $ | 2,084 |
| | $ | 3,876 |
| | $ | (1,792 | ) | | $ | 1,196 |
| | $ | 2,680 |
|
| Add (subtract): | | | | | | | | | |
Non-cash operating activities(a) | 7,580 |
| | 5,445 |
| | 2,135 |
| | 7,714 |
| | (2,269 | ) |
Pension and non-pension
postretirement benefit
contributions | (383 | ) | | (405 | ) | | 22 |
| | (397 | ) | | (8 | ) |
| Income taxes | 340 |
| | 299 |
| | 41 |
| | 576 |
| | (277 | ) |
Changes in working capital and other noncurrent assets and liabilities(b) | (1,016 | ) | | (1,605 | ) | | 589 |
| | (243 | ) | | (1,362 | ) |
| Option premiums received (paid), net | (43 | ) | | 28 |
| | (71 | ) | | (66 | ) | — |
| 94 |
|
Collateral received
(posted), net | 82 |
| | (158 | ) | | 240 |
| | 931 |
| | (1,089 | ) |
| Deposit with IRS | — |
| | — |
| | — |
| | (1,250 | ) | | 1,250 |
|
| Net cash flows provided by operations | $ | 8,644 |
| | $ | 7,480 |
| | $ | 1,164 |
| | $ | 8,461 |
| | $ | (981 | ) |
__________•See Note 24 —Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statement of Cash Flows for additional information on non-cash operating activity.
| |
(a) | Represents depreciation, amortization, depletion and accretion, net fair value changes related to derivatives, deferred income taxes, provision for uncollectible accounts, pension and non-pension postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense, impairment of long-lived assets, gain on sale of assets and businesses and other non-cash charges. See Note 23 —Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information on non-cash operating activity. |
| |
(b) | Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt. |
•See Note 14 —Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statement of Cash Flows for additional information on income taxes.
•Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the OTC markets.
•During 2020, Exelon and Generation derecognized approximately $1.2 billion of accounts receivable. See Note 6 — Accounts Receivable for additional information on the sales of customer accounts receivable.
Pension and Other Postretirement Benefits
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of contributing the greater of (1) $300 million until all the qualified plans are fullyachieving 100% funded status on an ABO basis and (2) the minimum amounts under ERISA to meet minimum contribution requirements and/or avoid benefit restrictions and at-risk status.over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $500 million in 2021. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.
While other postretirementOPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its other postretirement benefitOPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.
The following table provides all registrants'Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to other postretirementOPEB plans in 2019:2021:
| | | | Qualified Pension Plans | | Non-Qualified Pension Plans | | Other
Postretirement
Benefits | | Qualified Pension Plans | | Non-Qualified Pension Plans | | OPEB |
| Exelon | $ | 301 |
| | $ | 25 |
| | $ | 44 |
| Exelon | $ | 505 | | | $ | 51 | | | $ | 75 | |
| Generation | 135 |
| | 7 |
| | 13 |
| Generation | 196 | | | 27 | | | 24 | |
| ComEd | 65 |
| | 1 |
| | 2 |
| ComEd | 170 | | | 2 | | | 23 | |
| PECO | 25 |
| | 1 |
| | — |
| PECO | 14 | | | 1 | | | 0 | |
| BGE | 34 |
| | 1 |
| | 15 |
| BGE | 57 | | | 1 | | | 16 | |
| BSC | 41 |
| | 7 |
| | 2 |
| |
| | PHI | 1 |
| | 8 |
| | 12 |
| PHI | 29 | | | 9 | | | 7 | |
| Pepco | — |
| | 2 |
| | 10 |
| Pepco | 1 | | | 2 | | | 6 | |
| DPL | — |
| | 1 |
| | — |
| DPL | 0 | | | 1 | | | 0 | |
| ACE | — |
| | — |
| | 1 |
| ACE | 3 | | | 0 | | | 0 | |
| PHISCO | 1 |
| | 5 |
| | 1 |
| |
|
To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.
Cash flows provided by operating activities for the year ended December 31, 2018, 2017 and 2016 by Registrant were as follows:
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Exelon | $ | 8,644 |
| | $ | 7,480 |
| | $ | 8,461 |
|
| Generation | 3,861 |
| | 3,299 |
| | 4,442 |
|
| ComEd | 1,749 |
| | 1,527 |
| | 2,505 |
|
| PECO | 739 |
| | 755 |
| | 829 |
|
| BGE | 789 |
| | 821 |
| | 945 |
|
| Pepco | 474 |
| | 407 |
| | 651 |
|
| DPL | 352 |
| | 321 |
| | 310 |
|
| ACE | 228 |
| | 206 |
| | 385 |
|
|
| | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | 2018 | 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| PHI | $ | 1,132 |
| $ | 950 |
| | $ | 888 |
| | | $ | 264 |
|
Changes in Registrants' cash flows from operations for 2018, 2017, and 2016 were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business. In addition, significant operating cash flow impacts for the Registrants for 2018, 2017 and 2016 were as follows:
Generation
Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the OTC
markets. During 2018, 2017 and 2016, Generation had net collections (payments) of counterparty cash collateral of $64 million, $(129) million and $923 million, respectively, primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position.
During 2018, 2017 and 2016, Generation had net (payments) collections of approximately $(43) million, $28 million and $(66) million, respectively, related to purchases and sales of options. The level of option activity in a given year may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.
For additional information regarding changes in non-cash operating activities, see Note 23 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements.
Cash Flows from Investing Activities (All Registrants)
CashThe following table provides a summary of the change in cash flows used infrom investing activities for the yearyears ended December 31, 2018, 20172020 and 20162019 by Registrant were as follows:Registrant:
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Exelon | $ | (7,834 | ) | | $ | (7,971 | ) | | $ | (15,450 | ) |
| Generation | (2,531 | ) | | (2,662 | ) | | (3,816 | ) |
| ComEd | (2,097 | ) | | (2,230 | ) | | (2,685 | ) |
| PECO | (840 | ) | | (597 | ) | | (797 | ) |
| BGE | (950 | ) | | (875 | ) | | (910 | ) |
| Pepco | (654 | ) | | (628 | ) | | (616 | ) |
| DPL | (362 | ) | | (429 | ) | | (336 | ) |
| ACE | (334 | ) | | (313 | ) | | (307 | ) |
|
| | | | | | | | | | | | | | | | |
| | Successor | | | | Predecessor |
| | 2018 | 2017 | | March 24, 2016 to December 31, 2016 | | | | January 1, 2016 to March 23, 2016 |
| PHI | $ | (1,371 | ) | $ | (1,397 | ) | | $ | (993 | ) | | | | $ | (346 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Increase (decrease) in cash flows from investing activities | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Capital expenditures | $ | (800) | | | $ | 98 | | | $ | (302) | | | $ | (208) | | | $ | (102) | | | $ | (249) | | | $ | (147) | | | $ | (76) | | | $ | (26) | |
| Proceeds from NDT fund sales, net | (87) | | | (87) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Acquisitions of assets and businesses, net | 41 | | | 41 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Proceeds from sales of assets and businesses | (7) | | | (6) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Changes in intercompany money pool | — | | | — | | | — | | | 136 | | | — | | | — | | | — | | | — | | | — | |
| Collection of DPP | 3,771 | | | 3,771 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Other investing activities | 6 | | | 8 | | | (27) | | | 8 | | | (6) | | | 10 | | | (3) | | | (4) | | | 7 | |
| Increase (decrease) in cash flows from investing activities | $ | 2,924 | | | $ | 3,825 | | | $ | (329) | | | $ | (64) | | | $ | (108) | | | $ | (239) | | | $ | (150) | | | $ | (80) | | | $ | (19) | |
Significant investing cash flow impacts for the Registrants for 2018, 20172020 and 20162019 were as follows:
Exelon
During 2016, Exelon had•Variances in capital expenditures of $6.6 billion related are primarily due to the PHI merger.timing of cash expenditures for capital projects. Refer below for additional information on projected capital expenditure spending.
During 2016, Exelon had proceeds•Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
Exelon and Generation
During 2018, Exelon and Generation had expenditures of $81 million and $57 related to the acquisitions of the Everett Marine Terminal and the Handley generating station, respectively.
During 2018, Exelon and Generation had proceeds of $85 million relating to the sale of Generation’s interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution services.
During 2017, Exelon and Generation had additional expenditures of $23 million and $178 million related to the acquisitions of ConEdison Solutions and the FitzPatrick nuclear generating station, respectively.
During 2017, Exelon and Generation had proceeds of $218 million from sales of long-lived assets, primarily related to the sale back of turbine equipment.
During 2016, Exelon and Generation had expenditures of $235 million and $58 million related to the acquisitions of ConEdison Solutions and the FitzPatrick nuclear generating station, respectively.
Capital Expenditure Spending
CapitalThe Registrants most recent estimates of capital expenditures by Registrant for 2018, 2017plant additions and 2016 and projected amountsimprovements for 20192021 are approximately as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| (in millions) | Transmission | | Distribution | | Gas | | Total |
| Exelon | N/A | | N/A | | N/A | | $ | 7,775 | |
| Generation | N/A | | N/A | | N/A | | 1,150 | |
| ComEd | 475 | | | 1,925 | | | N/A | | 2,400 | |
| PECO | 175 | | | 750 | | | 350 | | | 1,275 | |
| BGE | 325 | | | 450 | | | 425 | | | 1,200 | |
| PHI | 525 | | | 1,100 | | | 75 | | | 1,700 | |
| Pepco | 250 | | | 675 | | | N/A | | 925 | |
| DPL | 125 | | | 225 | | | 75 | | | 425 | |
| ACE | 150 | | | 200 | | | N/A | | 350 | |
|
| | | | | | | | | | | | | | | |
| | Projected 2019 (a) | | 2018 | | 2017 | | 2016 |
Exelon(b) | $ | 7,325 |
| | $ | 7,594 |
| | $ | 7,584 |
| | $ | 8,553 |
|
| Generation | 1,950 |
| | 2,242 |
| | 2,259 |
| | 3,078 |
|
| ComEd | 1,875 |
| | 2,126 |
| | 2,250 |
| | 2,734 |
|
| PECO | 975 |
| | 849 |
| | 732 |
| | 686 |
|
BGE | 1,100 |
| | 959 |
| | 882 |
| | 934 |
|
| Pepco | 725 |
| | 656 |
| | 628 |
| | 586 |
|
| DPL | 350 |
| | 364 |
| | 428 |
| | 349 |
|
| ACE | 300 |
| | 335 |
| | 312 |
| | 311 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | | | Successor | | | | Predecessor |
| | Projected 2019 (a) | | 2018 | 2017 | | March 24, 2016 to December 31, 2016 | | | | January 1, 2016 to March 23, 2016 |
PHI(c) | $ | 1,375 |
| | $ | 1,375 |
| $ | 1,396 |
| | $ | 1,008 |
| | | | $ | 273 |
|
__________
| |
(a) | Total projected capital expenditures do not include adjustments for non-cash activity. Amounts are rounded to the nearest $25 million. |
| |
(b) | Includes corporate operations, BSC and PHISCO. |
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Generation
Approximately 43% and 8%48% of the projected 20192021 capital expenditures at Generation are for the acquisition of nuclear fuel, and the construction of new natural gas plants and solar facilities, respectively, with the remaining amounts primarily reflecting investment in renewable energy and additions and upgrades to existing generation facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that it will fund capital expenditures with internally generated funds and borrowings.
ComEd, PECO, BGE, Pepco, DPL and ACEUtility Registrants
Projected 20192021 capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as the Utility Registrants' construction commitments under PJM’s RTEP.
The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. In 2010, NERC provided guidance to transmission owners that recommended the Utility Registrants perform assessments of their transmission lines. ComEd, PECO, and BGE submitted their final bi-annual reports to NERC in January 2014. ComEd and PECO will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd’s and PECO’s forecasted 20192021 capital expenditures above reflect capital spending for remediation to be completed through 2019.2021. ComEd, BGE, Pepco, DPL, and ACE are complete with their assessments and Pepco has substantially completed its assessment and thus do not expect significant capital expenditures related to this guidance in 2019.
2021.
The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent.
Cash Flows from Financing Activities (All Registrants)
CashThe following tables provides a summary of the change in cash flows (used in) provided byfrom financing activities for the yearyears ended December 31, 2018, 20172020 and 20162019 by RegistrantRegistrant:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Increase (decrease) in cash flows from financing activities | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Changes in short-term borrowings, net | $ | 5 | | | $ | 200 | | | $ | 63 | | | $ | — | | | $ | (116) | | | $ | 131 | | | $ | (89) | | | $ | 34 | | | $ | 186 | |
| Long-term debt, net | 403 | | | (958) | | | 100 | | | 25 | | | — | | | 146 | | | 162 | | | 35 | | | (53) | |
| Changes in intercompany money pool | — | | | 385 | | | — | | | 40 | | | — | | | (3) | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| Dividends paid on common stock | (84) | | | — | | | 9 | | | 18 | | | (22) | | | — | | | (19) | | | (2) | | | 10 | |
| Distributions to member | — | | | (835) | | | — | | | — | | | — | | | (27) | | | — | | | — | | | — | |
| Contributions from parent/member | — | | | 23 | | | 462 | | | 60 | | | 218 | | | 96 | | | 102 | | | 49 | | | (58) | |
| | | | | | | | | | | | | | | | | |
| Other financing activities | (121) | | | (19) | | | 3 | | | 2 | | | — | | | (5) | | | (3) | | | (1) | | | — | |
| Increase (decrease) in cash flows from financing activities | $ | 203 | | | $ | (1,204) | | | $ | 637 | | | $ | 145 | | | $ | 80 | | | $ | 338 | | | $ | 153 | | | $ | 115 | | | $ | 85 | |
Significant financing cash flow impacts for the Registrants for 2020 and 2019 were as follows:
•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 17 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings.
•Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to debt issuances and redemptions tables below for additional information.
•Changes inintercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
•Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 19 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on dividend restrictions. See below for quarterly dividends declared.
•For the years ended December 31, 2020 and 2019, other financing activities primarily consists of debt issuance costs. See debt issuances table below for additional information on the Registrants’ debt issuances.
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Exelon | $ | (219 | ) | | $ | 767 |
| | $ | 1,191 |
|
| Generation | (981 | ) | | (531 | ) | | (734 | ) |
| ComEd | 534 |
| | 789 |
| | 169 |
|
| PECO | (39 | ) | | 50 |
| | (263 | ) |
| BGE | 156 |
| | 22 |
| | (21 | ) |
| Pepco | 193 |
| | 219 |
| | — |
|
| DPL | 32 |
| | 64 |
| | 67 |
|
| ACE | 105 |
| | 5 |
| | 22 |
|
|
| | | | | | | | | | | | | | | | |
| | Successor | | | | Predecessor |
| | 2018 | 2017 | | March 24, 2016 to December 31, 2016 | | | | January 1, 2016 to March 23, 2016 |
| PHI | $ | 330 |
| $ | 306 |
| | $ | (7 | ) | | | | $ | 372 |
|
Debt Issuances and Redemptions
See Note 1317 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances and retirements.long-term debt. Debt activity for 2018, 20172020 and 20162019 by Registrant was as follows:
During 2018,2020, the following long-term debt was issued:
| | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds |
| Generation | | Energy Efficiency Project Financing(a) | | 3.72 | % | | March 31, 2019 | | $ | 4 |
| | Funding to install energy conservation measures for the Smithsonian Zoo project. | |
| Exelon | | Exelon | | Notes | | 4.05 | % | | April 15, 2030 | | $ | 1,250 | | | Repay existing indebtedness and for general corporate purposes. |
| Exelon | | Exelon | | Notes | | 4.70 | % | | April 15, 2050 | | 750 | | Repay existing indebtedness and for general corporate purposes. |
| Generation | | Energy Efficiency Project Financing(a) | | 3.17 | % | | January 31, 2019 | | $ | 1 |
| | Funding to install energy conservation measures in Brooklyn, NY. | Generation | | Senior Notes | | 3.25 | % | | June 1, 2025 | | 900 | | Repay existing indebtedness and for general corporate purposes. |
| Generation | | Energy Efficiency Project Financing(a) | | 2.61 | % | | September 30, 2018 | | $ | 5 |
| | Funding to install energy conservation measures for the Pensacola project. | Generation | | EGR IV Nonrecourse Debt(a) | | LIBOR + 2.75% | | December 15, 2027 | | 750 | | Repay existing indebtedness and for general corporate purposes. |
| Generation | | Energy Efficiency Project Financing(a) | | 4.17 | % | | January 31, 2019 | | $ | 1 |
| | Funding to install energy conservation measures for the General Services Administration Philadelphia project. | Generation | | Energy Efficiency Project Financing(b)
| | 3.95 | % | | February 28, 2021 | | 3 | | Funding to install energy conservation measures for the Fort Meade project. |
| Generation | | Energy Efficiency Project Financing(a) | | 4.26 | % | | May 31, 2019 | | $ | 3 |
| | Funding to install energy conservation measures for the National Institutes of Health Multi-Buildings Phase II project. | Generation | | Energy Efficiency Project Financing(b) | | 2.53 | % | | March 31, 2021 | | 3 | | Funding to install energy conservation measures for the Fort AP Hill project. |
| ComEd | | First Mortgage Bonds, Series 124 | | 4.00 | % | | March 1, 2048 | | $ | 800 |
| | Refinance one series of maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and to fund general corporate purposes | ComEd | | First Mortgage Bonds, Series 128 | | 2.20 | % | | March 1, 2030 | | 350 | | Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes. |
| ComEd | | First Mortgage Bonds, Series 125 | | 3.70 | % | | August 15, 2028 | | $ | 550 |
| | Repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes. | ComEd | | First Mortgage Bonds, Series 129 | | 3.00 | % | | March 1, 2050 | | 650 | | Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes. |
| | PECO | | First and Refunding Mortgage Bonds | | 3.90 | % | | March 1, 2048 | | $ | 325 |
| | Refinance a portion of maturing mortgage bonds. | PECO | | First and Refunding Mortgage Bonds | | 2.80 | % | | June 15, 2050 | | 350 | | Funding for general corporate purposes. |
| PECO | | Loan Agreement | | 2.00 | % | | June 20, 2023 | | $ | 50 |
| | Funding to implement Electric Long-term Infrastructure Improvement Plan | |
| PECO | | First and Refunding Mortgage Bonds | | 3.90 | % | | March 1, 2048 | | $ | 325 |
| | Satisfy short-term borrowings from the Exelon intercompany money pool and for general corporate purposes. | |
| | BGE | | Senior Notes | | 4.25 | % | | September 15, 2048 | | $ | 300 |
| | Repay commercial paper obligations and for general corporate purposes. | BGE | | Senior Notes | | 2.90 | % | | June 15, 2050 | | 400 | | Repay commercial paper obligations and for general corporate purposes. |
| Pepco | | First Mortgage Bonds | | 4.27 | % | | June 15, 2048 | | $ | 100 |
| | Repay outstanding commercial paper and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 2.53 | % | | February 25, 2030 | | 150 | | Repay existing indebtedness and for general corporate purposes. |
| Pepco | | First Mortgage Bonds | | 4.31 | % | | November 1, 2048 | | $ | 100 |
| | Repay outstanding commercial paper and for general corporate purposes. | Pepco | | First Mortgage Bonds | | 3.28 | % | | September 23, 2050 | | 150 | | Repay existing indebtedness and for general corporate purposes. |
| DPL | | First Mortgage Bonds | | 4.27 | % | | June 15, 2048 | | $ | 200 |
| | Repay outstanding commercial paper and for general corporate purposes. | DPL | | First Mortgage Bonds | | 2.53 | % | | June 9, 2030 | | 100 | | Repay existing indebtedness and for general corporate purposes. |
| DPL | | DPL | | Tax-Exempt Bonds(c) | | 1.05 | % | | January 1, 2031 | | 78 | | Refinance existing indebtedness. |
| ACE | | First Mortgage Bonds | | 4.00 | % | | October 15, 2028 | | $ | 350 |
| | Refinance ACE’s 7.75% First Mortgage Bonds due November 15, 2018, reduce short-term borrowings and for general corporate purposes. | ACE | | Tax-Exempt First Mortgage Bonds | | 2.25 | % | | June 1, 2029 | | 23 | | Refinance existing indebtedness. |
| ACE | | ACE | | First Mortgage Bonds | | 3.24 | % | | June 9, 2050 | | 100 | | Repay existing indebtedness and for general corporate purposes. |
__________
| |
(a) | For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. |
(a)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
(b)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
(c)The bonds have a 1.05% interest rate through July 2025.
During 2017,2019, the following long termlong-term debt was issued:
| | | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds |
| Exelon Corporate | | Junior Subordinated Notes | | 3.50 | % | | June 1, 2022 | | $ | 1,150 |
| | Refinance Exelon's Junior Subordinated Notes issued in June 2014. | |
| Generation | | Albany Green Energy Project Financing(a) | | LIBOR + 1.25% |
| | November 17, 2017 | | $ | 14 |
| | Albany Green Energy biomass generation development. | |
| Generation | | Energy Efficiency Project Financing(a) | | 3.90 | % | | February 1, 2018 | | $ | 19 |
| | Funding to install energy conservation measures for the Naval Station Great Lakes project. | |
| Generation | | Energy Efficiency Project Financing(a) | | 3.72 | % | | May 1, 2018 | | $ | 5 |
| | Funding to install energy conservation measures for the Smithsonian Zoo project. | |
| Generation | | Energy Efficiency Project Financing(a) | | 2.61 | % | | September 30, 2018 | | $ | 13 |
| | Funding to install energy conservation measures for the Pensacola project. | |
| Generation | | Energy Efficiency Project Financing(a) | | 3.53 | % | | April 1, 2019 | | $ | 8 |
| | Funding to install energy conservation measures for the State Department project. | |
| Generation | | Senior Notes | | 2.95 | % | | January 15, 2020 | | $ | 250 |
| | Repay outstanding commercial paper obligations and for general corporate purposes. | |
| Generation | | Senior Notes | | 3.40 | % | | March 15, 2020 | | $ | 500 |
| | Repay outstanding commercial paper obligations and for general corporate purposes. | Generation | | Energy Efficiency Project Financing(a) | | 3.95 | % | | February 28, 2021 | | $ | 4 | | | Funding to install energy conservation measures for the Fort Meade project. |
| Generation | | ExGen Texas Power Nonrecourse Debt(b)(c) | | LIBOR + 4.75% |
| | September 18, 2021 | | $ | 6 |
| | General corporate purposes. | Generation | | Energy Efficiency Project Financing(a) | | 3.46 | % | | February 28, 2021 | | 39 | | Funding to install energy conservation measures for the Marine Corps. Logistics Project. |
| Generation | | ExGen Renewables IV, Nonrecourse Debt(b) | | LIBOR + 3.00% |
| | November 30, 2024 | | $ | 850 |
| | General corporate purposes. | Generation | | Energy Efficiency Project Financing(a) | | 2.53 | % | | March 31, 2021 | | 2 | | Funding to install energy conservation measures for the Fort AP Hill project. |
| ComEd | | First Mortgage Bonds, Series 122 | | 2.95 | % | | August 15, 2027 | | $ | 350 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes | ComEd | | First Mortgage Bonds, Series 126 | | 4.00 | % | | March 1, 2049 | | 400 | | Repay a portion of ComEd’s outstanding commercial paper obligations and fund other general corporate purposes. |
| ComEd | | First Mortgage Bonds, Series 123 | | 3.75 | % | | August 15, 2047 | | $ | 650 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes. | ComEd | | First Mortgage Bonds, Series 127 | | 3.20 | % | | November 15, 2049 | | 300 | | Repay a portion of ComEd’s outstanding commercial paper obligations and fund other general corporate purposes. |
| PECO | | First and Refunding Mortgage Bonds | | 3.70 | % | | September 15, 2047 | | $ | 325 |
| | General corporate purposes. | PECO | | First and Refunding Mortgage Bonds | | 3.00 | % | | September 15, 2049 | | 325 | | Repay short-term borrowings and for general corporate purposes. |
| BGE | | Senior Notes | | 3.75 | % | | August 15, 2047 | | $ | 300 |
| | Redeem $250 million in principal amount of the 6.20% Deferrable Interest Subordinated Debentures due October 15, 2043 issued by BGE's affiliate BGE Capital Trust II, repay commercial paper obligations and for general corporate purposes. | BGE | | Senior Notes | | 3.20 | % | | September 15, 2049 | | 400 | | Repay commercial paper obligations and for general corporate purposes. |
| Pepco | | Energy Efficiency Project Financing(a) | | 3.30 | % | | December 15, 2017 | | $ | 2 |
| | Funding to install energy conservation measures for the DOE Germantown project. | Pepco | | First Mortgage Bonds | | 3.45 | % | | June 13, 2029 | | 150 | | Repay existing indebtedness and for general corporate purposes. |
| Pepco | | First Mortgage Bonds | | 4.15 | % | | March 15, 2043 | | $ | 200 |
| | Funding to repay outstanding commercial paper and for general corporate purposes. | Pepco | | Unsecured Tax-Exempt Bonds | | 1.70 | % | | September 1, 2022 | | 110 | | Refinance existing indebtedness. |
| DPL | | DPL | | First Mortgage Bonds | | 4.14 | % | | December 12, 2049 | | 75 | | Repay existing indebtedness and for general corporate purposes. |
| ACE | | ACE | | First Mortgage Bonds | | 3.50 | % | | May 21, 2029 | | 100 | | Repay existing indebtedness and for general corporate purposes. |
| ACE | | ACE | | First Mortgage Bonds | | 4.14 | % | | May 21, 2049 | | 50 | | Repay existing indebtedness and for general corporate purposes. |
|
__________
| |
(a) | For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. |
(a)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
| |
(b) | See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt. |
| |
(c) | As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. See Note 5 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. |
During 2016, the following long term-debt was issued:
|
| | | | | | | | | | | | | |
| Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds |
| Exelon Corporate | | Senior Unsecured Notes | | 2.45 | % | | April 15, 2021 | | $ | 300 |
| | Repay commercial paper issued by PHI and for general corporate purposes. |
| Exelon Corporate | | Senior Unsecured Notes | | 3.40 | % | | April 15, 2026 | | $ | 750 |
| | Repay commercial paper issued by PHI and for general corporate purposes. |
| Exelon Corporate | | Senior Unsecured Notes | | 4.45 | % | | April 15, 2046 | | $ | 750 |
| | Repay commercial paper issued by PHI and for general corporate purposes. |
| Generation | | Renewable Power Generation Nonrecourse Debt(a)
| | 4.11 | % | | March 31, 2035 | | $ | 150 |
| | Paydown long-term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general corporate purposes. |
| Generation | | Albany Green Energy Project Financing(b) | | LIBOR + 1.25% |
| | November 17, 2017 | | $ | 98 |
| | Albany Green Energy biomass generation development. |
| Generation | | Energy Efficiency Project Financing(b) | | 3.17 | % | | December 31, 2017 | | $ | 16 |
| | Funding to install energy conservation measures in Brooklyn, NY. |
| Generation | | Energy Efficiency Project Financing(b) | | 3.90 | % | | January 31, 2018 | | $ | 19 |
| | Funding to install energy conservation measures for the Naval Station Great Lakes project. |
| Generation | | Energy Efficiency Project Financing(b) | | 3.52 | % | | April 30, 2018 | | $ | 14 |
| | Funding to install energy conservation measures for the Smithsonian Zoo project. |
| Generation | | SolGen Nonrecourse Debt(a) | | 3.93 | % | | September 30, 2036 | | $ | 150 |
| | General corporate purposes. |
| Generation | | Energy Efficiency Project Financing(b) | | 3.46 | % | | October 1, 2018 | | $ | 36 |
| | Funding to install energy conservation measures or the Marine Corps Logistics Base project. |
| Generation | | Energy Efficiency Project Financing(b) | | 2.61 | % | | September 30, 2018 | | $ | 4 |
| | Funding to install energy conservation measures for the Pensacola project. |
| ComEd | | First Mortgage Bonds, Series 120 | | 2.55 | % | | June 15, 2026 | | $ | 500 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes. |
| ComEd | | First Mortgage Bonds, Series 121 | | 3.65 | % | | June 15, 2046 | | $ | 700 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes. |
| PECO | | First Mortgage Bonds | | 1.70 | % | | September 15, 2021 | | $ | 300 |
| | Refinance maturing mortgage bonds. |
| BGE | | Notes | | 2.40 | % | | August 15, 2026 | | $ | 350 |
| | Redeem the $190M of outstanding preference shares and for general corporate purposes. |
|
| | | | | | | | | | | | | |
| BGE | | Notes | | 3.50 | % | | August 15, 2046 | | 500 | | Redeem the $190M of outstanding preference shares and for general corporate purposes. |
| Pepco | | Energy Efficiency Project Financing(b) | | 3.30 | % | | December 15, 2017 | | 4 | | Funding to install energy conservation measures for the DOE Germantown project. |
| DPL | | First Mortgage Bonds | | 4.15 | % | | May 15, 2045 | | 175 | | Refinance maturing mortgage bonds, repay commercial paper and for general corporate purposes. |
__________
| |
(a) | See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt. |
| |
(b) | For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. |
During 2018,2020, the following long-term debt was retired and/or redeemed:
| | | Company | | Type | | Interest Rate | | Maturity | | Amount | Company | | Type | | Interest Rate | | Maturity | | Amount |
| Exelon Corporate | | Long-Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 6 |
| |
| Exelon | | Exelon | | Notes | | 2.85% | | June 15, 2020 | | $ | 900 | |
| Exelon | | Exelon | | Long-Term Software License Agreement | | 3.95% | | May 1, 2024 | | 24 |
| Generation | | Naval Station Great Lakes Project Financing | | 3.90% | | June 30, 2018 | | $ | 41 |
| Generation | | Senior Notes | | 2.95% | | January 15, 2020 | | 1,000 | |
| Generation | | Smithsonian Zoo Project Financing | | 3.72% | | March 31, 2019 | | $ | 1 |
| Generation | | Senior Notes | | 4.00% | | October 1, 2020 | | 550 |
| Generation | | Pensacola Project Financing | | 2.61% | | September 30, 2018 | | $ | 21 |
| Generation | | Senior Notes(a) | | 5.15% | | December 1, 2020 | | 550 |
| Generation | | Fort Detrick Project Financing | | 3.55% | | June 30, 2019 | | $ | 19 |
| Generation | | Tax-Exempt Bonds | | 2.50% - 2.70% | | December 1, 2025 - June 1, 2036 | | 412 |
| Generation | | Holyoke Nonrecourse Debt(a) | | 5.25% | | December 31, 2031 | | $ | 1 |
| Generation | | EGR IV Nonrecourse Debt(b) | | 3 month LIBOR + 3.00% | | November 30, 2024 | | 796 |
| Generation | | SolGen Nonrecourse Debt(a) | | 3.93% | | September 30, 2036 | | $ | 10 |
| Generation | | Continental Wind Nonrecourse Debt(b) | | 6.00% | | February 28, 2033 | | 33 |
| Generation | | Antelope Valley DOE Nonrecourse Debt(a) | | 2.29% - 3.56% | | January 5, 2037 | | $ | 22 |
| Generation | | Antelope Valley DOE Nonrecourse Debt(b) | | 2.29% - 3.56% | | January 5, 2037 | | 23 |
| Generation | | Continental Wind Nonrecourse Debt(a) | | 6.00% | | February 28, 2033 | | $ | 33 |
| Generation | | RPG Nonrecourse Debt(b) | | 4.11% | | March 31, 2035 | | 9 |
| Generation | | Renewable Power Generation Nonrecourse Debt(a) | | 4.11% | | March 31, 2035 | | $ | 11 |
| Generation | | Energy Efficiency Project Financing | | 3.71% | | December 31, 2020 | | 4 |
| Generation | | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 4 |
| Generation | | NUKEM | | 3.15% | | September 30, 2020 | | 3 |
| Generation | | ExGen Renewables IV Nonrecourse Debt | | 3mL+300 bps | | November 30, 2024 | | $ | 16 |
| Generation | | SolGen Nonrecourse Debt | | 3.93% | | September 30, 2036 | | 3 |
| Generation | | NUKEM | | 3.15% - 3.35% | | 2018 - 2020 | | $ | 43 |
| Generation | | Energy Efficiency Project Financing | | 4.12% | | November 30, 2020 | | 1 |
| ComEd | | First Mortgage Bonds | | 5.80% | | March 15, 2018 | | $ | 700 |
| ComEd | | First Mortgage Bonds | | 4.00% | | August 1, 2020 | | 500 |
| ComEd | | Notes | | 6.95% | | July 15, 2018 | | $ | 140 |
| |
| PECO | | First Mortgage Bonds | | 5.35% | | March 1, 2018 | | $ | 500 |
| |
| DPL | | Medium Term Notes, Unsecured | | 6.81% | | January 9, 2018 | | $ | 4 |
| DPL | | Tax-Exempt Bonds | | 5.40% | | February 1, 2031 | | 78 |
| Pepco | | Notes | | 3.30% | | August 31, 2018 | | $ | 5 |
| |
| Pepco | | Third Party Financing | | 7.28-7.99% | | 2021 - 2023 | | $ | 1 |
| |
| ACE | | First Mortgage Bonds | | 7.75% | | November 15, 2018 | | $ | 250 |
| ACE | | Tax-Exempt First Mortgage Bonds | | 4.88% | | June 1, 2029 | | 23 |
| ACE | | Transition Bonds | | 5.05% - 5.55% | | 2020 - 2023 | | $ | 31 |
| ACE | | Transition Bonds | | 5.55% | | October 20, 2023 | | 20 |
|
__________
| |
(a) | See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt. |
(a)The senior notes are legacy Constellation mirror debt that were previously held at Exelon and Generation. As part of the 2012 Constellation merger, Exelon and Generation assumed intercompany loan agreements that mirrored the terms and amounts of external obligations held by Exelon, resulting in intercompany notes payable at Generation.
(b)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
During 2017,2019, the following long-term debt was retired and/or redeemed:
| | | Company | | Type | | Interest Rate | | Maturity | | Amount | Company | | Type | | Interest Rate | | Maturity | | Amount |
| Exelon Corporate | | Long-Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 24 |
| |
| Exelon Corporate | | Senior Notes | | 1.55% | | June 9, 2017 | | $ | 550 |
| |
| Exelon | | Exelon | | Long-Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 18 | |
| Generation | | Generation | | Antelope Valley DOE Nonrecourse Debt(a) | | 2.33% - 3.56% | | January 5, 2037 | | 23 |
| Generation | | Generation | | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | 5 |
| Generation | | Generation | | Continental Wind Nonrecourse Debt(a) | | 6.00% | | February 28, 2033 | | 32 |
| Generation | | Generation | | Pollution control notes | | 2.50% | | March 1, 2019 | | 23 |
| Generation | | Senior Notes - Exelon Wind | | 2.00% | | July 31, 2017 | | $ | 1 |
| Generation | | RPG Nonrecourse Debt(a) | | 4.11% | | March 31, 2035 | | 10 |
| Generation | | CEU Upstream Nonrecourse Debt(a) | | LIBOR + 2.25% | | January 14, 2019 | | $ | 6 |
| Generation | | Energy Efficiency Project Financing | | 3.46% | | April 30, 2019 | | 39 |
| Generation | | SolGen Nonrecourse Debt(a) | | 3.93% | | September 30, 2036 | | $ | 2 |
| Generation | | EGR IV Nonrecourse Debt(a) | | 3 month LIBOR + 3.00% | | November 30, 2024 | | 38 |
| Generation | | Antelope Valley DOE Nonrecourse Debt(a) | | 2.29% - 3.56% | | January 5, 2037 | | $ | 22 |
| Generation | | Hannie Mae, LLC Defense Financing | | 4.12% | | November 30, 2019 | | 1 |
| Generation | | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 2 |
| Generation | | Energy Efficiency Project Financing | | 3.72% | | July 31, 2019 | | 25 |
| Generation | | Continental Wind Nonrecourse Debt(a) | | 6.00% | | February 28, 2033 | | $ | 31 |
| Generation | | NUKEM | | 3.15% | | September 30, 2020 | | 36 |
| Generation | | PES - PGOV Notes Payable | | 6.70-7.60% | | 2017 - 2018 | | $ | 1 |
| Generation | | SolGen Nonrecourse Debt(a) | | 3.93% | | September 30, 2036 | | 6 |
| Generation | | ExGen Texas Power Nonrecourse Debt(a)(b) | | LIBOR + 4.75% | | September 18, 2021 | | $ | 665 |
| Generation | | Energy Efficiency Project Financing | | 4.17% | | October 31, 2019 | | 1 |
| Generation | | Renewable Power Generation Nonrecourse Debt(a) | | 4.11% | | March 31, 2035 | | $ | 14 |
| Generation | | Energy Efficiency Project Financing | | 3.53% | | March 31, 2020 | | 1 |
| Generation | | NUKEM | | 3.25% - 3.35% | | June 30, 2018 | | $ | 23 |
| Generation | | Energy Efficiency Project Financing | | 4.26% | | September 30, 2019 | | 1 |
| Generation | | ExGen Renewables I, Nonrecourse Debt | | LIBOR + 4.25% | | February 6, 2021 | | $ | 233 |
| Generation | | Senior Notes | | 5.20% | | October 1, 2019 | | 600 |
| Generation | | Senior Notes | | 6.20% | | October 1, 2017 | | $ | 700 |
| Generation | | Dominion Federal Corp | | 3.17% | | October 31, 2019 | | 18 |
| Generation | | Albany Green Energy Project Financing | | LIBOR + 1.25% | | November 17, 2017 | | $ | 212 |
| Generation | | Fort Detrick Project Financing | | 3.55% | | October 31, 2019 | | 1 |
| ComEd | | First Mortgage Bonds | | 6.15% | | September 15, 2017 | | $ | 425 |
| ComEd | | First Mortgage Bonds | | 2.15% | | January 15, 2019 | | 300 |
| BGE | | Rate Stabilization Bonds | | 5.82% | | April 1, 2017 | | $ | 41 |
| |
| BGE | | Capital Trust Preferred Securities | | 6.20% | | October 15, 2043 | | $ | 258 |
| |
| PHI | | Senior Notes | | 6.13% | | June 1, 2017 | | $ | 81 |
| |
| Pepco | | Pepco | | Secured Tax-Exempt Bonds | | 6.20% - 7.49% | | 2021 - 2022 | | 110 |
| DPL | | Medium Term Notes, Unsecured | | 7.56% - 7.58% | | February 1, 2017 | | $ | 14 |
| DPL | | Medium Term Notes, Unsecured | | 7.61% | | December 2, 2019 | | 12 |
| DPL | | Variable Rate Demand Bonds | | Variable | | October 1, 2017 | | $ | 26 |
| |
| Pepco | | Third Party Financing | | 6.97% - 7.99% | | 2018 - 2022 | | $ | 1 |
| |
| ACE | | Transition Bonds | | 5.05% - 5.55% | | 2020 - 2023 | | $ | 35 |
| ACE | | Transition Bonds | | 5.55% | | October 20, 2023 | | 18 |
__________
| |
(a) | See Note 13(a)See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt. |
| |
(b) | As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. See Note 5 — Mergers, Acquisitions and Dispositions for additional information. |
During 2016, the following long-term debt was retired and/or redeemed:Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
|
| | | | | | | | | | |
| Company | | Type | | Interest Rate | | Maturity | | Amount |
| Exelon Corporate | | Long Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 8 |
|
| Exelon Corporate | | Senior Notes | | 4.95% | | June 15, 2035 | | $ | 1 |
|
| Generation | | Antelope Valley DOE Nonrecourse Debt(a) | | 2.29% - 3.56% | | January 5, 2037 | | $ | 22 |
|
| Generation | | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 4 |
|
| Generation | | Continental Wind Nonrecourse Debt(a) | | 6.00% | | February 28, 2033 | | $ | 29 |
|
| Generation | | CEU Upstream Nonrecourse Debt(a) | | LIBOR + 2.25% | | January 14, 2019 | | $ | 46 |
|
| Generation | | ExGen Texas Power Nonrecourse Debt(a)(b) | | 5.00% | | September 18, 2021 | | $ | 7 |
|
| Generation | | Sacramento Solar Nonrecourse Debt | | LIBOR + 2.25% | | December 31, 2030 | | $ | 33 |
|
| Generation | | Clean Horizons Nonrecourse Debt | | LIBOR + 2.25% | | September 7, 2030 | | $ | 32 |
|
| Generation | | ExGen Renewables I, Nonrecourse Debt | | LIBOR + 4.25% | | February 6, 2021 | | $ | 24 |
|
| Generation | | PES - PGOV Notes Payable | | 6.70% - 7.46% | | 2017-2018 | | $ | 1 |
|
| Generation | | NUKEM | | 3.35% | | June 30, 2018 | | $ | 12 |
|
| Generation | | NUKEM | | 3.25% | | July 1, 2018 | | $ | 10 |
|
| Generation | | Renewable Power Generation Nonrecourse Debt(a) | | 4.11% | | March 31, 2035 | | $ | 9 |
|
| Generation | | SolGen Nonrecourse Debt(a) | | 3.93% | | September 30, 2036 | | $ | 2 |
|
| ComEd | | First Mortgage Bonds, Series 104 | | 5.95% | | August 15, 2016 | | $ | 415 |
|
| ComEd | | First Mortgage Bonds, Series 111 | | 1.95% | | August 1, 2016 | | $ | 250 |
|
| PECO | | First and Refunding Mortgage Bonds | | 1.20% | | October 15, 2016 | | $ | 300 |
|
| BGE | | Rate Stabilization Bonds | | 5.72% | | April 1, 2016 | | $ | 1 |
|
| BGE | | Rate Stabilization Bonds | | 5.82% | | April 1, 2017 | | $ | 38 |
|
| BGE | | Notes | | 5.90% | | October 1, 2016 | | $ | 300 |
|
| BGE | | Rate Stabilization Bonds | | 5.82% | | April 1, 2017 | | $ | 40 |
|
| PHI | | Senior Unsecured Notes | | 5.90% | | December 12, 2016 | | $ | 190 |
|
| DPL | | First Mortgage Bonds | | 5.22% | | December 30, 2016 | | $ | 100 |
|
| ACE | | Transition Bonds | | 5.05% | | October 20, 2020 | | $ | 12 |
|
| ACE | | Transition Bonds | | 5.55% | | October 20, 2023 | | $ | 34 |
|
| ACE | | First Mortgage Bonds | | 7.68% | | August 23, 2016 | | $ | 2 |
|
__________
| |
(a) | See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt. |
| |
(b) | As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. See Note 5 — Mergers, Acquisitions and Dispositions for additional information. |
From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt on their respective balance sheets.
Dividends
Cash dividend payments and distributions for the year ended December 31, 2018, 2017 and 2016 by Registrant were as follows:
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Exelon | $ | 1,332 |
| | $ | 1,236 |
| | $ | 1,166 |
|
| Generation | 1,001 |
| | 659 |
| | 922 |
|
| ComEd | 459 |
| | 422 |
| | 369 |
|
| PECO | 306 |
| | 288 |
| | 277 |
|
BGE(a) | 209 |
| | 198 |
| | 187 |
|
| Pepco | 169 |
| | 133 |
| | 136 |
|
| DPL | 96 |
| | 112 |
| | 54 |
|
| ACE | 59 |
| | 68 |
| | 63 |
|
|
| | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | 2018 | | 2017 | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| PHI | $ | 326 |
| | $ | 311 |
| $ | 273 |
| | | $ | — |
|
__________
| |
(a) | Includes dividends paid on BGE's preference stock during 2016. |
Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 20182020 and for the first quarter of 20192021 were as follows:
|
| | | | | | | | | | |
| Period | | Declaration Date | | Shareholder of Record Date | | Dividend Payable Date | | Cash per Share(a) |
| First Quarter 2018 | | January 30, 2018 | | February 15, 2018 | | March 9, 2018 | | $ | 0.3450 |
|
| Second Quarter 2018 | | May 1, 2018 | | May 15, 2018 | | June 8, 2018 | | $ | 0.3450 |
|
| Third Quarter 2018 | | July 24, 2018 | | August 15, 2018 | | September 10, 2018 | | $ | 0.3450 |
|
| Fourth Quarter 2018 | | September 24, 2018 | | November 15, 2018 | | December 1, 2018 | | $ | 0.3450 |
|
| First Quarter 2019 | | February 5, 2019 | | February 20, 2019 | | March 8, 2019 | | $ | 0.3625 |
|
___________
| | | | | | | | | | | | | | | | | | | | | | | | | | |
(a)Period | Exelon's Board | Declaration Date | | Shareholder of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 throughRecord Date | | Dividend Payable Date | | Cash per Share(a) |
First Quarter 2020 beginning with the | | January 28, 2020 | | February 20, 2020 | | March 2018 dividend.10, 2020 |
Short-Term Borrowings
Short-term borrowings incurred (repaid) during 2018, 2017 and 2016 by Registrant were as follows:
|
| | | | | | | | | | | |
| 2018 |
| 2017 |
| 2016 |
| Exelon | $ | (338 | ) | | $ | (261 | ) | �� | $ | (353 | ) |
| Generation | — |
| | (620 | ) | | 620 |
|
| ComEd | — |
| | — |
| | (294 | ) |
| BGE | (42 | ) | | 32 |
| | (165 | ) |
| Pepco | 14 |
| | 3 |
| | (41 | ) |
| DPL | (216 | ) | | 216 |
| | (105 | ) |
| ACE | (94 | ) | | 108 |
| | (5 | ) |
|
| | | | | | | | | | | | | | |
| | Successor | | | | Predecessor |
| | 2018 | 2017 | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| PHI | $ | (296 | ) | $ | 328 |
| $ | (515 | ) | | | $ | (121 | ) |
Retirement of Long-Term Debt to Financing Affiliates
On August 28, 2017, BGE redeemed all of the outstanding shares of BGE Capital Trust II 6.20% Preferred Securities.
Contributions from Parent/Member
Contributions from Parent/Member (Exelon) during 2018, 2017 and 2016 by Registrant were as follows:
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
| Generation | $ | 155 |
| | $ | 102 |
| | $ | 142 |
|
ComEd(a)(b) | 500 |
| | 672 |
| | 473 |
|
PECO(b) | 89 |
| | 16 |
| | 18 |
|
BGE(b) | 109 |
| | 184 |
| | 61 |
|
Pepco(c) | 166 |
| | 161 |
| | 187 |
|
DPL(c) | 150 |
| | — |
| | 152 |
|
ACE(c) | 67 |
| | — |
| | 139 |
|
|
| | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | 2018 | | 2017 | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| PHI | $ | 385 |
| | $ | 758 |
| $ | 1,251 |
| | | $ | — |
|
__________
| $ | 0.3825 | |
(a)Second Quarter 2020 | Additional contributions from parent or external debt financing may be required as a result of increased capital investment in infrastructure improvements and modernization pursuant to EIMA, transmission upgrades and expansions and Exelon's agreement to indemnify ComEd for any unfavorable after-tax impacts associated with ComEd's LKE tax matter. |
| April 28, 2020 | | May 15, 2020 | | June 10, 2020 | | $ | 0.3825 | |
(b)Third Quarter 2020 | Contribution paid by Exelon. |
| July 28, 2020 | | August 14, 2020 | | September 10, 2020 | | $ | 0.3825 | |
(c)Fourth Quarter 2020 | Contribution paid by PHI. | November 2, 2020 | | November 16, 2020 | | December 10, 2020 | | $ | 0.3825 | |
| First Quarter 2021 | | February 21, 2021 | | March 8, 2021 | | March 15, 2021 | | $ | 0.3825 | |
Pursuant to___________
(a)Exelon's Board of Directors approved an updated dividend policy for 2021. The 2021 quarterly dividend will remain the orders approvingsame as the PHI merger, Exelon made equity contributions2020 dividend of $73 million, $46 million and $49 million to Pepco, DPL and ACE, respectively, in the second quarter$0.3825 per share.
Redemptions of Preference Stock. BGE had $190 million of cumulative preference stock that was redeemable at its option at any time after October 1, 2015 for the redemption price of $100 per share, plus accrued and unpaid dividends. On July 3, 2016, BGE redeemed all 400,000 shares of its outstanding 7.125% Cumulative Preference Stock, 1993 Series and all 600,000 shares of its outstanding 6.990% Cumulative Preference Stock, 1995 Series for $100 million, plus accrued and unpaid dividends. On September 18, 2016, BGE redeemed the remaining 500,000 shares of its outstanding 6.970% Cumulative Preference Stock, 1993 Series and the remaining 400,000 shares of its outstanding 6.700% Cumulative Preference Stock, 1993 Series for $90 million, plus accrued and unpaid dividends. As of December 31, 2018, BGE no longer has any preferred stock outstanding.
Other
For the year ended December 31, 2018, other financing activities primarily consists of debt issuance costs. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements’ for additional information.
Credit Matters
Market Conditions (All Registrants)
The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $9.7$10.6 billion (including bilateral credit facilities and credit facilities for project finance) in aggregate total commitments of which $8.0$7.7 billion was available to support additional commercial paper as of December 31, 2018,2020, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper marketmarkets and had availability under their revolving credit facilities during 20182020 to fund their short-term liquidity needs, when necessary. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS for additional information regarding the effects of uncertainty in the capital and credit markets.
The Registrants believe their cash flow from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of December 31, 2018,2020, it would have been required to provide incremental collateral of $2.1approximately $1.5 billion to meet collateral obligations for derivatives, non-derivatives, normal purchases and normal sales contracts, and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within the $4.1$4.7 billion of available credit capacity of its revolver.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at December 31, 20182020 and available credit facility capacity prior to any incremental collateral at December 31, 2018:2020:
| | | | PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral | | PJM Credit Policy Collateral | | Other Incremental Collateral Required(a) | | Available Credit Facility Capacity Prior to Any Incremental Collateral |
| ComEd | $ | 9 |
| | $ | — |
| | $ | 998 |
| ComEd | $ | 13 | | | $ | — | | | $ | 675 | |
| PECO | — |
| | 39 |
| | 600 |
| PECO | 2 | | | 34 | | | 600 | |
| BGE | 12 |
| | 69 |
| | 599 |
| BGE | 10 | | | 54 | | | 600 | |
| Pepco | 11 |
| | — |
| | 292 |
| Pepco | 8 | | | — | | | 264 | |
| DPL | 5 |
| | 11 |
| | 299 |
| DPL | 4 | | | 9 | | | 154 | |
| ACE | — |
| | — |
| | 300 |
| ACE | — | | | — | | | 113 | |
__________
| |
(a) | Represents incremental collateral related to natural gas procurement contracts. |
(a)Represents incremental collateral related to natural gas procurement contracts.
Exelon Credit Facilities
Exelon Corporate, ComEd, BGE, Pepco, DPL and ACEBGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool.The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
See Note 1317 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ credit facilities and short term borrowing activity.
Capital Structure.Structure
At December 31, 2018,2020, the capital structures of the Registrants consisted of the following:
| |
| Exelon |
| Generation |
| ComEd |
| PECO |
| BGE | | PHI | | Pepco | | DPL | | ACE | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Long-term debt | 51 | % | | 32 | % | | 44 | % | | 44 | % | | 46 | % | | 40 | % | | 49 | % | | 50 | % | | 48 | % | Long-term debt | 50 | % | | 27 | % | | 43 | % | | 44 | % | | 47 | % | | 40 | % | | 49 | % | | 48 | % | | 47 | % |
Long-term debt to affiliates(a) | 1 | % | | 4 | % | | 1 | % | | 3 | % | | — | % | | — | % | | — | % | | — | % | | — | % | Long-term debt to affiliates(a) | 1 | % | | 1 | % | | 1 | % | | 2 | % | | — | % | | — | % | | — | % | | — | % | | — | % |
| Common equity | 47 | % | | — | % | | 55 | % | | 53 | % | | 53 | % | | — |
| | 50 | % | | 50 | % | | 46 | % | Common equity | 46 | % | | — | % | | 54 | % | | 54 | % | | 53 | % | | — | % | | 50 | % | | 48 | % | | 47 | % |
| Member’s equity | — | % | | 64 | % | | — | % | | — | % | | — | % | | 59 | % | | — |
| | — |
| | — |
| Member’s equity | — | % | | 68 | % | | — | % | | — | % | | — | % | | 58 | % | | — | % | | — | % | | — | % |
| | Commercial paper and notes payable | 1 | % | | — | % | | — |
| | — | % | | 1 | % | | 1 | % | | 1 | % | | — | % | | 6 | % | Commercial paper and notes payable | 3 | % | | 4 | % | | 2 | % | | — | % | | — | % | | 2 | % | | 1 | % | | 4 | % | | 6 | % |
__________
| |
(a) | Includes approximately $390 million, $205 million and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatorily redeemable trust preferred securities of ComEd and PECO. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs. |
(a)Includes approximately $390 million, $205 million, and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatorily redeemable trust preferred securities of ComEd and PECO. See Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 1216 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The credit ratings for Exelon Corporate, PECO, BGE, PHI, Pepco, DPL, and ACE did not change for the twelve months ended December 31, 2020. On November 4, 2020, S&P revised its assessment of the strategic relationship between Exelon and Generation and subsequently lowered Generation's senior unsecured debt rating to 'BBB' from 'BBB+'. On July 21, 2020, S&P lowered ComEd's long-term issuer credit rating from 'A-' to a 'BBB+'. S&P also affirmed the current 'A' rating on ComEd's senior secured debt and 'A-2' short-term rating, which influences long and short-term borrowing cost.
Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of December 31, 2018,2020, are presented in the following tables:
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2020 | | As of December 31, 2020 |
| Exelon Intercompany Money Pool | Maximum
Contributed | | Maximum
Borrowed | | Contributed (Borrowed) |
| Exelon Corporate | $ | 1,364 | | | $ | — | | | $ | 598 | |
| Generation | 254 | | | (980) | | | (285) | |
| PECO | 292 | | | (40) | | | (40) | |
| BSC | 25 | | | (563) | | | (312) | |
| PHI Corporate | — | | | (22) | | | (21) | |
| PCI | 60 | | | — | | | 60 | |
|
| | | | | | | | | | | |
| Exelon Intercompany Money Pool | For the Year Ended December 31, 2018 | | As of
December 31, 2018 |
| Contributed (borrowed) | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) |
| Exelon Corporate | $ | 674 |
| | $ | — |
| | $ | 216 |
|
| Generation | 227 |
| | (389 | ) | | (100 | ) |
| PECO | 285 |
| | (420 | ) | | — |
|
| BSC | — |
| | (403 | ) | | (173 | ) |
| PHI Corporate | — |
| | (35 | ) | | — |
|
| PCI | 57 |
| | (1 | ) | | 57 |
|
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2020 | | As of December 31, 2020 |
| PHI Intercompany Money Pool | Maximum
Contributed | | Maximum
Borrowed | | Contributed (Borrowed) |
| | | | | |
| Pepco | $ | 166 | | | $ | (57) | | | $ | — | |
| DPL | 62 | | | (95) | | | — | |
| ACE | — | | | (133) | | | — | |
| | | | | |
Shelf Registration Statements |
| | | | | | | | | | | |
| PHI Intercompany Money Pool | For the Year Ended December 31, 2018 | | As of
December 31, 2018 |
| Contributed (borrowed) | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) |
| PHI Corporate | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| PHISCO | 34 |
| | — |
| | 3 |
|
Investments in NDT Funds.Exelon, Generation, and CENG maintain trust funds, as required by the NRC, to fund certain costs of decommissioning nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with Generation’s NDT fund investment policy. Generation’s and CENG's investment policies establish limits on the concentration of holdings in any one company and also in any one industry. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.
Shelf Registration Statements. Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACEUtility Registrants have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 2019.2022. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.
Regulatory Authorizations. ComEd, PECO, BGE, Pepco, DPL and ACEAuthorizations
The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
| | | | | | | | | | | | | | | | | As of December 31, 2020 |
| | | Short-term Financing Authority(a) | | Long-term Financing Authority(a) | | Short-term Financing Authority(a) | | Long-term Financing Authority(a) |
| Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount (c) | Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount |
ComEd(b) | | FERC | | December 31, 2019 | | $ | 2,500 |
| | ICC | | 2019 & 2021 | | $ | 1,533 |
| ComEd(b) | | FERC | | December 31, 2021 | | $ | 2,500 | | | ICC | | February 1, 2023 | | $ | 893 | |
| PECO | | FERC | | December 31, 2019 | | 1,500 |
| | PAPUC | | December 31, 2021 | | 1,900 |
| PECO | | FERC | | December 31, 2021 | | 1,500 | | | PAPUC | | December 31, 2021 | | 1,225 | |
| BGE | | FERC | | December 31, 2019 | | 700 |
| | MDPSC | | N/A | | 400 |
| BGE | | FERC | | December 31, 2021 | | 700 | | | MDPSC | | N/A | | 1,100 | |
| Pepco | | FERC | | December 31, 2019 | | 500 |
| | MDPSC / DCPSC | | December 31, 2020 | | 400 |
| Pepco | | FERC | | December 31, 2021 | | 500 | | | MDPSC / DCPSC | | December 31, 2022 | | 900 | |
| DPL | | FERC | | December 31, 2019 | | 500 |
| | MDPSC / DPSC | | December 31, 2020 | | 150 |
| DPL | | FERC | | December 31, 2021 | | 500 | | | MDPSC / DPSC | | December 31, 2022 | | 297 | |
ACE | | NJBPU | | December 31, 2019 | | 350 |
| | NJBPU | | December 31, 2019 | | — |
| | NJBPU | | December 31, 2021 | | 350 | | | NJBPU | | December 31, 2022 | | 600 | |
__________
| |
(a) | (a)Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority. (b)As of December 31, 2020, ComEd had $893 million in new money long-term debt financing authority from the ICC with an expiration date of February 1, 2023. On January 20, 2021, ComEd received $350 million of long-term debt refinancing authority from the ICC approved with an effective date of February 1, 2021 and an expiration date of February 1, 2024. (c)On December 2, 2020, ACE received approval from FERC in connection with its market-based rate authority. |
| |
(b) | ComEd had $440 million available in long-term debt refinancing authority and $1,093 million available in new money long-term debt financing authority from the ICC as of December 31, 2018 and has an expiration date of June 1, 2019 and August 1, 2021, respectively. |
| |
(c) | ACE is currently in the process of requesting its long-term debt financing authority. |
Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings.
ComEd is subject to restrictions in the event that (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued.
PECO is subject to restrictions in the event that (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade.
Pepco, DPL and ACE are subject to certain dividend restrictions established by settlements approved in the District of Columbia, Maryland, Delaware, and New Jersey. Pepco, DPL and ACE are prohibited from paying a dividend on their common shares if (a) after the dividend payment, Pepco's, DPL's or ACE's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the DCPSC, MDPSC, DPSC, and NJBPU or (b) Pepco's, DPL's or ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percentfor $600 million in new long-term debt financing authority with an effective date of its total capitalization, excluding securitization debt, falls below 30%.January 1, 2021.
At December 31, 2018, Exelon had retained earnings
Table of $14,766 million, including Generation’s undistributed earnings of $3,724 million, ComEd’s retained earnings of $1,337 million consisting of retained earnings appropriated for future dividends of $2,976 million partially offset by $1,639 million of unappropriated retained deficit, PECO’s retained earnings of $1,242 million, BGE’s retained earnings $1,640 million, and PHI's undistributed earnings of $62 million. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding fund transfer restrictions.Contents
Contractual Obligations and Off-Balance Sheet Arrangements
The following tables summarize the Registrants’ future estimated cash payments as of December 31, 20182020 under existing contractual obligations, including payments due by period.
Exelon
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payment due within |
| Total | | 2021 | | 2022 -
2023 | | 2024 -
2025 | | 2026
and beyond |
Long-term debt(a) | $ | 36,839 | | | $ | 1,809 | | | $ | 3,933 | | | $ | 3,012 | | | $ | 28,085 | |
Interest payments on long-term debt(b) | 24,486 | | | 1,468 | | | 2,766 | | | 2,592 | | | 17,660 | |
Operating leases(c) | 1,213 | | | 141 | | | 224 | | | 193 | | | 655 | |
Purchase power obligations(d) | 1,613 | | | 512 | | | 823 | | | 264 | | | 14 | |
Fuel purchase agreements(e) | 5,667 | | | 1,183 | | | 1,584 | | | 1,237 | | | 1,663 | |
| Electric supply procurement | 3,170 | | | 1,909 | | | 1,253 | | | 8 | | | — | |
| Long-term renewable energy and REC commitments | 2,238 | | | 301 | | | 548 | | | 437 | | | 952 | |
Other purchase obligations(f) | 9,374 | | | 6,673 | | | 1,492 | | | 440 | | | 769 | |
| DC PLUG obligation | 100 | | | 30 | | | 60 | | | 10 | | | — | |
| SNF obligation | 1,208 | | | — | | | — | | | — | | | 1,208 | |
| | | | | | | | | |
Pension contributions(g) | 3,030 | | | 505 | | | 1,010 | | | 1,010 | | | 505 | |
| Total contractual obligations | $ | 88,938 | | | $ | 14,531 | | | $ | 13,693 | | | $ | 9,203 | | | $ | 51,511 | |
__________
(a)Includes amounts from ComEd and PECO financing trusts.
(b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2020. Includes estimated interest payments due to ComEd and PECO financing trusts.
(c)Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $98 million, $55 million, $44 million, $44 million, $44 million, and $179 million for 2021, 2022, 2023, 2024, 2025, and thereafter, respectively and $464 million in total.
(d)Purchase power obligations primarily include expected payments for REC purchases and payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature.
(e)Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity, and services, including those related to CENG.
(f)Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
(g)These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2026 are not included.
Generation
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payment due within |
| Total | | 2021 | | 2022 -
2023 | | 2024 -
2025 | | 2026
and beyond |
| Long-term debt | $ | 6,066 | | | $ | 195 | | | $ | 1,024 | | | $ | 900 | | | $ | 3,947 | |
Interest payments on long-term debt(a) | 3,536 | | | 270 | | | 474 | | | 443 | | | 2,349 | |
Operating leases(b) | 731 | | | 47 | | | 114 | | | 109 | | | 461 | |
Purchase power obligations(c) | 1,613 | | | 512 | | | 823 | | | 264 | | | 14 | |
Fuel purchase agreements(d) | 4,450 | | | 928 | | | 1,207 | | | 1,022 | | | 1,293 | |
Other purchase obligations(e) | 2,286 | | | 1,208 | | | 231 | | | 155 | | | 692 | |
| SNF obligation | 1,208 | | | — | | | — | | | — | | | 1,208 | |
| Total contractual obligations | $ | 19,890 | | | $ | 3,160 | | | $ | 3,873 | | | $ | 2,893 | | | $ | 9,964 | |
__________
(a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2020.
(b)Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $98 million, $55 million, $44 million, $44 million, $44 million, and $179 million for 2021, 2022, 2023, 2024, 2025, and thereafter, respectively and $464 million in total.
(c)Purchase power obligations primarily include expected payments for REC purchases and capacity payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature.
(d)Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity, and services, including those related to CENG.
(e)Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Generation and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
ComEd
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payment due within |
| Total | | 2021 | | 2022 -
2023 | | 2024 -
2025 | | 2026
and beyond |
Long-term debt(a) | $ | 9,284 | | | $ | 350 | | | $ | — | | | $ | 250 | | | $ | 8,684 | |
Interest payments on long-term debt(b) | 7,207 | | | 360 | | | 720 | | | 711 | | | 5,416 | |
| Operating leases | 8 | | | 3 | | | 3 | | | 2 | | | — | |
| Electric supply procurement | 600 | | | 388 | | | 212 | | | — | | | — | |
| Long-term renewable energy and REC commitments | 1,953 | | | 269 | | | 485 | | | 384 | | | 815 | |
Other purchase obligations(c) | 1,524 | | | 1,397 | | | 74 | | | 35 | | | 18 | |
| ZEC commitments | 1,127 | | | 176 | | | 351 | | | 351 | | | 249 | |
| Total contractual obligations | $ | 21,703 | | | $ | 2,943 | | | $ | 1,845 | | | $ | 1,733 | | | $ | 15,182 | |
__________
(a)Includes amounts from ComEd financing trust.
(b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the ComEd financing trust.
(c)Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ComEd and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
PECO
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payment due within |
| Total | | 2021 | | 2022 -
2023 | | 2024 -
2025 | | 2026
and beyond |
Long-term debt(a) | $ | 3,984 | | | $ | 300 | | | $ | 400 | | | $ | 350 | | | $ | 2,934 | |
Interest payments on long-term debt(b) | 2,867 | | | 146 | | | 280 | | | 271 | | | 2,170 | |
| Operating leases | 1 | | | 1 | | | — | | | — | | | — | |
Fuel purchase agreements(c) | 405 | | | 138 | | | 183 | | | 41 | | | 43 | |
| Electric supply procurement | 536 | | | 431 | | | 105 | | | — | | | — | |
Other purchase obligations(d) | 898 | | | 813 | | | 66 | | | 19 | | | — | |
| Total contractual obligations | $ | 8,691 | | | $ | 1,829 | | | $ | 1,034 | | | $ | 681 | | | $ | 5,147 | |
__________
(a)Includes amounts from PECO financing trusts.
(b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the PECO financing trusts.
(c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.
(d)Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PECO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
BGE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payment due within |
| Total | | 2021 | | 2022 -
2023 | | 2024 -
2025 | | 2026
and beyond |
| Long-term debt | $ | 3,700 | | | $ | 300 | | | $ | 550 | | | $ | — | | | $ | 2,850 | |
Interest payments on long-term debt(a) | 2,450 | | | 127 | | | 240 | | | 220 | | | 1,863 | |
| Operating leases | 81 | | | 46 | | | 17 | | | — | | | 18 | |
Fuel purchase agreements(b) | 517 | | | 84 | | | 128 | | | 109 | | | 196 | |
| Electric supply procurement | 1,088 | | | 665 | | | 423 | | | — | | | — | |
Other purchase obligations(c) | 1,372 | | | 976 | | | 364 | | | 26 | | | 6 | |
| Total contractual obligations | $ | 9,208 | | | $ | 2,198 | | | $ | 1,722 | | | $ | 355 | | | $ | 4,933 | |
__________
(a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.
(b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.
(c)Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
PHI
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payment due within |
| Total | | 2021 | | 2022 -
2023 | | 2024 -
2025 | | 2026
and beyond |
| Long-term debt | $ | 6,443 | | | $ | 339 | | | $ | 809 | | | $ | 700 | | | $ | 4,595 | |
Interest payments on long-term debt(a) | 4,135 | | | 266 | | | 517 | | | 447 | | | 2,905 | |
| Finance leases | 53 | | | 8 | | | 16 | | | 16 | | | 13 | |
| Operating leases | 306 | | | 40 | | | 77 | | | 69 | | | 120 | |
Fuel purchase agreements(b) | 295 | | | 33 | | | 66 | | | 65 | | | 131 | |
| Electric supply procurement | 1,791 | | | 1,051 | | | 732 | | | 8 | | | — | |
| Long-term renewable energy and REC commitments | 285 | | | 32 | | | 63 | | | 53 | | | 137 | |
Other purchase obligations(c) | 1,767 | | | 1,362 | | | 341 | | | 48 | | | 16 | |
| DC PLUG obligation | 100 | | | 30 | | | 60 | | | 10 | | | — | |
| Total contractual obligations | $ | 15,175 | | | $ | 3,161 | | | $ | 2,681 | | | $ | 1,416 | | | $ | 7,917 | |
__________
(a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2020.
(b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.
(c)Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco, DPL, ACE, and PHISCO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
Pepco
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payment due within |
| Total | | 2021 | | 2022 -
2023 | | 2024 -
2025 | | 2026
and beyond |
| Long-term debt | $ | 3,185 | | | $ | — | | | $ | 309 | | | $ | 400 | | | $ | 2,476 | |
Interest payments on long-term debt(a) | 2,429 | | | 147 | | | 281 | | | 251 | | | 1,750 | |
| Finance leases | 18 | | | 3 | | | 6 | | | 6 | | | 3 | |
| Operating leases | 63 | | | 8 | | | 15 | | | 12 | | | 28 | |
| Electric supply procurement | 754 | | | 432 | | | 314 | | | 8 | | | — | |
Other purchase obligations(b) | 1,034 | | | 748 | | | 243 | | | 32 | | | 11 | |
| DC PLUG obligation | 100 | | | 30 | | | 60 | | | 10 | | | — | |
| Total contractual obligations | $ | 7,583 | | | $ | 1,368 | | | $ | 1,228 | | | $ | 719 | | | $ | 4,268 | |
__________
(a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.
(b)Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
DPL
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payment due within |
| Total | | 2021 | | 2022 -
2023 | | 2024 -
2025 | | 2026
and beyond |
| Long-term debt | $ | 1,666 | | | $ | 79 | | | $ | 500 | | | $ | — | | | $ | 1,087 | |
Interest payments on long-term debt(a) | 1,016 | | | 59 | | | 116 | | | 82 | | | 759 | |
| Finance leases | 21 | | | 3 | | | 6 | | | 6 | | | 6 | |
| Operating leases | 80 | | | 11 | | | 19 | | | 15 | | | 35 | |
Fuel purchase agreements(b) | 295 | | | 33 | | | 66 | | | 65 | | | 131 | |
| Electric supply procurement | 469 | | | 290 | | | 179 | | | — | | | — | |
| Long-term renewable energy and associated REC commitments | 285 | | | 32 | | | 63 | | | 53 | | | 137 | |
Other purchase obligations(c) | 419 | | | 349 | | | 63 | | | 7 | | | — | |
| Total contractual obligations | $ | 4,251 | | | $ | 856 | | | $ | 1,012 | | | $ | 228 | | | $ | 2,155 | |
__________
(a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2020.
(b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.
(c)Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between DPL and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
ACE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payment due within |
| Total | | 2021 | | 2022 -
2023 | | 2024 -
2025 | | 2026
and beyond |
| Long-term debt | $ | 1,407 | | | $ | 259 | | | $ | — | | | $ | 300 | | | $ | 848 | |
Interest payments on long-term debt (a) | 527 | | | 46 | | | 92 | | | 86 | | | 303 | |
| Finance leases | 14 | | | 2 | | | 4 | | | 4 | | | 4 | |
| Operating leases | 16 | | | 5 | | | 7 | | | 4 | | | — | |
| Electric supply procurement | 568 | | | 329 | | | 239 | | | — | | | — | |
Other purchase obligations(b) | 267 | | | 236 | | | 25 | | | 6 | | | — | |
| Total contractual obligations | $ | 2,799 | | | $ | 877 | | | $ | 367 | | | $ | 400 | | | $ | 1,155 | |
__________
(a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early redemptions, or debt issuances.
(b)Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
See Note 2219 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ commercial and other commitments, representing commitments potentially triggered by future events.
Exelon
|
| | | | | | | | | | | | | | | | | | | |
| | | | Payment due within | | |
| | Total | | 2019 |
| 2020 -
2021 |
| 2022 -
2023 |
| Due 2024
and beyond |
Long-term debt(a) | $ | 35,265 |
| | $ | 1,328 |
| | $ | 5,033 |
| | $ | 3,933 |
| | $ | 24,971 |
|
Interest payments on long-term debt(b) | 22,840 |
| | 1,446 |
| | 2,689 |
| | 2,372 |
| | 16,333 |
|
| Capital leases | 36 |
| | 21 |
| | 6 |
| | 1 |
| | 8 |
|
Operating leases(c)(d) | 1,378 |
| | 140 |
| | 292 |
| | 223 |
| | 723 |
|
Purchase power obligations(e) | 1,121 |
| | 365 |
| | 484 |
| | 98 |
| | 174 |
|
Fuel purchase agreements(f) | 5,984 |
| | 1,235 |
| | 2,078 |
| | 1,269 |
| | 1,402 |
|
Electric supply procurement(f) | 2,836 |
| | 1,828 |
| | 1,008 |
| | — |
| | — |
|
AEC purchase commitments(f) | 2 |
| | 1 |
| | 1 |
| | — |
| | — |
|
Curtailment services commitments(f) | 129 |
| | 29 |
| | 74 |
| | 26 |
| | — |
|
Long-term renewable energy and REC commitments(g) | 1,838 |
| | 137 |
| | 265 |
| | 274 |
| | 1,162 |
|
Other purchase obligations(h) | 6,626 |
| | 4,676 |
| | 1,323 |
| | 247 |
| | 380 |
|
DC PLUG obligation(i) | 160 |
| | 30 |
| | 60 |
| | 60 |
| | 10 |
|
Construction commitments(j) | 21 |
| | 21 |
| | — |
| | — |
| | — |
|
PJM regional transmission expansion commitments(k) | 396 |
| | 141 |
| | 237 |
| | 18 |
| | — |
|
SNF obligation(l) | 1,171 |
| | — |
| | — |
| | — |
| | 1,171 |
|
ZEC commitments(m) | 1,404 |
| | 168 |
| | 337 |
| | 332 |
| | 567 |
|
Pension contributions(n) | 2,276 |
| | 301 |
| | 616 |
| | 752 |
| | 607 |
|
| Total contractual obligations | $ | 83,483 |
| | $ | 11,867 |
|
| $ | 14,503 |
|
| $ | 9,605 |
|
| $ | 47,508 |
|
__________
| |
(a) | Includes $390 million due after 2024 to ComEd and PECO financing trusts. |
| |
(b) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2018. Includes estimated interest payments due to ComEd and PECO financing trusts. |
| |
(c) | Includes amounts related to shared use land arrangements. |
| |
(d) | Excludes Generation's contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power obligations. |
| |
(e) | Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts presented represent Generation’s expected payments under these arrangements at December 31, 2018. Expected payments include certain fixed capacity charges which may be reduced based on plant availability. Expected payments exclude renewable PPA contracts that are contingent in nature. Contained within Purchase power obligations are Net Capacity Purchases of $126 million, $56 million, $35 million, $26 million, $20 million and $155 million for 2019, 2020, 2021, 2022, 2023 and thereafter, respectively. |
| |
(f) | Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity and services, procure electric supply, and purchase AECs and curtailment services. |
| |
(g) | Primarily related to ComEd 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the earliest and maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. |
| |
(h) | Represents the future estimated value at December 31, 2018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(i) | Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover this charge from customers through a volumetric distribution rider. See Note 4Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information. |
| |
(j) | Represents commitments for Generation's ongoing investments in new natural gas generation construction. As of December 31, 2018, the commitments relate to the construction of a new dual fuel, natural peaking facility in Massachusetts. Achievement of commercial operation related to this project is expected in 2019. |
| |
(k) | Under their operating agreements with PJM, ComEd, PECO, BGE, DPL and ACE are committed to the construction of transmission facilities to maintain system reliability. These amounts represent ComEd, PECO, BGE, DPL and ACE’s expected portion of the costs to pay for the completion of the required construction projects. |
| |
(l) | See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding SNF obligations. |
| |
(m) | Annual ZEC commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year. Amounts presented in the table represent management's estimate of ComEd's obligation based on forward energy prices and load forecasts. ComEd is permitted to recover its ZEC costs from retail customers with no mark-up. |
| |
(n) | These amounts represent Exelon’s expected contributions to its qualified pension plans. The projected contributions reflect a funding strategy of contributing the greater of $300 million until all the qualified plans are fully funded on an ABO basis, and the minimum amounts under ERISA to avoid benefit restrictions and at-risk status. This level funding strategy helps minimize volatility of future period required pension contributions. These amounts represent estimates that are based on assumptions that are subject to change. Qualified pension contributions for years after 2024 are not included. See Note 16 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding estimated future pension benefit payments. |
Generation
|
| | | | | | | | | | | | | | | | | | | |
| | | | Payment due within | | |
| | Total | | 2019 | | 2020 -
2021 | | 2022 -
2023 | | Due 2024
and beyond |
| Long-term debt | $ | 8,745 |
| | $ | 899 |
| | $ | 2,103 |
| | $ | 1,023 |
| | $ | 4,720 |
|
Interest payments on long-term debt(a) | 4,333 |
| | 354 |
| | 592 |
| | 483 |
| | 2,904 |
|
| Capital leases | 14 |
| | 7 |
| | 6 |
| | 1 |
| | — |
|
Operating leases(b)(c) | 763 |
| | 33 |
| | 92 |
| | 93 |
| | 545 |
|
Purchase power obligations(d) | 1,121 |
| | 365 |
| | 484 |
| | 98 |
| | 174 |
|
Fuel purchase agreements(e) | 4,931 |
| | 1,013 |
| | 1,759 |
| | 1,078 |
| | 1,081 |
|
Other purchase obligations(f) | 1,742 |
| | 1,114 |
| | 224 |
| | 98 |
| | 306 |
|
Construction commitments(g) | 21 |
| | 21 |
| | — |
| | — |
| | — |
|
SNF obligation(h) | 1,171 |
| | — |
| | — |
| | — |
| | 1,171 |
|
| Total contractual obligations | $ | 22,841 |
| | $ | 3,806 |
|
| $ | 5,260 |
|
| $ | 2,874 |
|
| $ | 10,901 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2018. |
| |
(b) | Includes amounts related to shared use land arrangements. |
| |
(c) | Excludes Generation's contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power obligations. |
| |
(d) | Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts represent Generation’s expected payments under these arrangements at December 31, 2018. Expected payments include certain fixed capacity charges which may be reduced based on plant availability. Expected payments exclude renewable PPA contracts that are contingent in nature. Contained within Purchase power obligations are Net Capacity Purchases of $126 million, $56 million, $35 million, $26 million, $20 million and $155 million for 2019, 2020, 2021, 2022, 2023 and thereafter, respectively. |
| |
(e) | Primarily represents commitments to purchase fuel supplies for nuclear and fossil generation, including those related to CENG. |
| |
(f) | Represents the future estimated value at December 31, 2018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(g) | Represents commitments for Generation's ongoing investments in new natural gas generation construction. As of December 31, 2018, the commitments relate to the construction of a new dual fuel, natural peaking facility in Massachusetts. Achievement of commercial operation related to this project is expected in 2019. |
| |
(h) | See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding SNF obligations. |
ComEd
|
| | | | | | | | | | | | | | | | | | | |
| | | | Payment due within | | |
| | Total | | 2019 | | 2020 -
2021 | | 2022 -
2023 | | Due 2024
and beyond |
Long-term debt(a) | $ | 8,385 |
| | $ | 300 |
| | $ | 850 |
| | $ | — |
| | $ | 7,235 |
|
Interest payments on long-term debt(b) | 6,512 |
| | 339 |
| | 646 |
| | 614 |
| | 4,913 |
|
| Capital leases | 8 |
| | — |
| | — |
| | — |
| | 8 |
|
Operating leases(c) | 23 |
| | 7 |
| | 9 |
| | 7 |
| | — |
|
| Electric supply procurement | 650 |
| | 419 |
| | 231 |
| | — |
| | — |
|
Long-term renewable energy and REC commitments(d) | 1,497 |
| | 106 |
| | 203 |
| | 212 |
| | 976 |
|
Other purchase obligations(e) | 1,109 |
| | 1,050 |
| | 55 |
| | 2 |
| | 2 |
|
PJM regional transmission expansion commitments(f) | 176 |
| | 40 |
| | 136 |
| | — |
| | — |
|
ZEC commitments(g) | 1,404 |
| | 168 |
| | 337 |
| | 332 |
| | 567 |
|
| Total contractual obligations | $ | 19,764 |
| | $ | 2,429 |
|
| $ | 2,467 |
|
| $ | 1,167 |
|
| $ | 13,701 |
|
__________
| |
(a) | Includes $206 million due after 2024 to a ComEd financing trust. |
| |
(b) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2018. Includes estimated interest payments due to the ComEd financing trust. |
| |
(c) | Includes amounts related to shared use land arrangements. |
| |
(d) | Primarily related to ComEd 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum and earliest settlements with suppliers for renewable energy and RECs under the existing contract terms. |
| |
(e) | Represents the future estimated value at December 31, 2018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(f) | Under its operating agreement with PJM, ComEd is committed to the construction of transmission facilities to maintain system reliability. These amounts represent ComEd’s expected portion of the costs to pay for the completion of the required construction projects. |
| |
(g) | Annual ZEC commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year. Amounts presented in the table represent management's estimate of ComEd's obligation based on forward energy prices and load forecasts. ComEd is permitted to recover its ZEC costs from retail customers with no mark-up. |
PECO
|
| | | | | | | | | | | | | | | | | | | |
| | | | Payment due within | | |
| | Total | | 2019 | | 2020 -
2021 | | 2022 -
2023 | | Due 2024
and beyond |
Long-term debt(a) | $ | 3,309 |
| | $ | — |
| | $ | 300 |
| | $ | 400 |
| | $ | 2,609 |
|
Interest payments on long-term debt(b) | 2,562 |
| | 131 |
| | 261 |
| | 242 |
| | 1,928 |
|
Operating leases(c)(d) | 25 |
| | 5 |
| | 10 |
| | 10 |
| | — |
|
Fuel purchase agreements(e) | 335 |
| | 116 |
| | 151 |
| | 33 |
| | 35 |
|
Electric supply procurement(e) | 530 |
| | 453 |
| | 77 |
| | — |
| | — |
|
AEC purchase commitments(e) | 4 |
| | 2 |
| | 2 |
| | — |
| | — |
|
Other purchase obligations(f) | 668 |
| | 501 |
| | 156 |
| | 10 |
| | 1 |
|
PJM regional transmission expansion commitments(g) | 54 |
| | 27 |
| | 18 |
| | 9 |
| | — |
|
| Total contractual obligations | $ | 7,487 |
| | $ | 1,235 |
|
| $ | 975 |
|
| $ | 704 |
|
| $ | 4,573 |
|
__________
| |
(a) | Includes $184 million due after 2024 to PECO financing trusts. |
| |
(b) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| |
(c) | Includes amounts related to shared use land arrangements. |
| |
(d) | Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, PECO has excluded these payments from the remaining years as such amounts would not be meaningful. PECO’s average annual obligation for these arrangements, included in each of the years 2019 - 2023, was $5 million. Also includes amounts related to shared use land arrangements. |
| |
(e) | Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and purchase AECs. |
| |
(f) | Represents the future estimated value at December 31, 2018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(g) | Under its operating agreement with PJM, PECO is committed to the construction of transmission facilities to maintain system reliability. These amounts represent PECO’s expected portion of the costs to pay for the completion of the required construction projects. |
BGE
|
| | | | | | | | | | | | | | | | | | | |
| | | | Payment due within | | |
| | Total | | 2019 | | 2020 -
2021 | | 2022 -
2023 | | Due 2024
and beyond |
| Long-term debt | $ | 2,900 |
| | $ | — |
| | $ | 300 |
| | $ | 550 |
| | $ | 2,050 |
|
Interest payments on long-term debt(a) | 1,971 |
| | 113 |
| | 225 |
| | 191 |
| | 1,442 |
|
Operating leases(b)(c)(d)(e) | 143 |
| | 35 |
| | 68 |
| | 21 |
| | 19 |
|
Fuel purchase agreements(f) | 434 |
| | 76 |
| | 107 |
| | 94 |
| | 157 |
|
Electric supply procurement(f) | 1,070 |
| | 670 |
| | 400 |
| | — |
| | — |
|
Curtailment services commitments(f) | 61 |
| | 10 |
| | 38 |
| | 13 |
| | — |
|
Other purchase obligations(g) | 584 |
| | 528 |
| | 50 |
| | 2 |
| | 4 |
|
PJM regional transmission expansion commitments(h) | 89 |
| | 35 |
| | 54 |
| | — |
| | — |
|
| Total contractual obligations | $ | 7,252 |
| | $ | 1,467 |
|
| $ | 1,242 |
|
| $ | 871 |
|
| $ | 3,672 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| |
(b) | Includes amounts related to shared use land arrangements. |
| |
(c) | Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, BGE has excluded these payments from the remaining years as such amounts would not be meaningful. BGE’s average annual obligation for these arrangements, included in each of the years 2019 - 2023, was $1 million. Also includes amounts related to shared use land arrangements. |
| |
(d) | Includes all future lease payments on a 99-year real estate lease that expires in 2106. |
| |
(e) | The BGE table above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million, and $14 million related to years 2019 - 2022, respectively. |
| |
(f) | Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and curtailment services. |
| |
(g) | Represents the future estimated value at December 31, 2018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(h) | Under its operating agreement with PJM, BGE is committed to the construction of transmission facilities to maintain system reliability. These amounts represent BGE’s expected portion of the costs to pay for the completion of the required construction projects. |
PHI
|
| | | | | | | | | | | | | | | | | | | |
| | | | Payment due within | | |
| | Total | | 2019 | | 2020 -
2021 | | 2022 -
2023 | | Due 2024
and beyond |
| Long-term debt | $ | 5,622 |
| | $ | 111 |
| | $ | 281 |
| | $ | 810 |
| | $ | 4,420 |
|
Interest payments on long-term debt(a) | 4,192 |
| | 260 |
| | 512 |
| | 476 |
| | 2,944 |
|
| Capital leases | 14 |
| | 14 |
| | — |
| | — |
| | — |
|
Operating leases(b) | 377 |
| | 48 |
| | 89 |
| | 81 |
| | 159 |
|
Fuel purchase agreements(c) | 284 |
| | 30 |
| | 61 |
| | 64 |
| | 129 |
|
Long-term renewable energy and REC commitments(c) | 341 |
| | 31 |
| | 62 |
| | 62 |
| | 186 |
|
Electric supply procurement(c) | 1,635 |
| | 993 |
| | 642 |
| | — |
| | — |
|
Curtailment services commitments(c) | 68 |
| | 19 |
| | 36 |
| | 13 |
| | — |
|
Other purchase obligations(d) | 1,396 |
| | 893 |
| | 437 |
| | 34 |
| | 32 |
|
DC PLUG obligation(e) | 160 |
| | 30 |
| | 60 |
| | 60 |
| | 10 |
|
PJM regional transmission expansion commitments(f) | 77 |
| | 39 |
| | 29 |
| | 9 |
| | — |
|
| Total contractual obligations | $ | 14,166 |
| | $ | 2,468 |
| | $ | 2,209 |
| | $ | 1,609 |
| | $ | 7,880 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| |
(b) | Includes amounts related to shared use land arrangements. |
| |
(c) | Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric supply, and curtailment services. |
| |
(d) | Represents the future estimated value at December 31, 2018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(e) | Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover this charge from customers through a volumetric distribution rider. See Note 4 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information. |
| |
(f) | Under its operating agreement with PJM, PHI is committed to the construction of transmission facilities to maintain system reliability. These amounts represent PHI’s expected portion of the costs to pay for the completion of the required construction projects. |
Pepco
|
| | | | | | | | | | | | | | | | | | | |
| | | | Payment due within | | |
| | Total | | 2019 | | 2020 -
2021 | | 2022 -
2023 | | Due 2024
and beyond |
| Long-term debt | $ | 2,737 |
| | $ | 1 |
| | $ | 1 |
| | $ | 310 |
| | $ | 2,425 |
|
Interest payments on long-term debt(a) | 2,488 |
| | 138 |
| | 276 |
| | 256 |
| | 1,818 |
|
| Capital leases | 14 |
| | 14 |
| | — |
| | — |
| | — |
|
Operating leases(b) | 86 |
| | 11 |
| | 19 |
| | 16 |
| | 40 |
|
Electric supply procurement(c) | 663 |
| | 407 |
| | 256 |
| | — |
| | — |
|
Curtailment services commitments(c) | 33 |
| | 4 |
| | 20 |
| | 9 |
| | — |
|
Other purchase obligations(d) | 908 |
| | 509 |
| | 337 |
| | 31 |
| | 31 |
|
DC PLUG obligation(e) | 160 |
| | 30 |
| | 60 |
| | 60 |
| | 10 |
|
| Total contractual obligations | $ | 7,089 |
| | $ | 1,114 |
| | $ | 969 |
| | $ | 682 |
| | $ | 4,324 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| |
(b) | Includes amounts related to shared use land arrangements. |
| |
(c) | Represents commitments to purchase procure electric supply and curtailment services. |
| |
(d) | Represents the future estimated value at December 31, 2018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(e) | Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover this charge from customers through a volumetric distribution rider. See Note 4 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information. |
DPL
|
| | | | | | | | | | | | | | | | | | | |
| | | | Payment due within | | |
| | Total | | 2019 | | 2020 -
2021 | | 2022 -
2023 | | Due 2024
and beyond |
| Long-term debt | $ | 1,504 |
| | $ | 91 |
| | $ | — |
| | $ | 500 |
| | $ | 913 |
|
Interest payments on long-term debt(a) | 1,050 |
| | 57 |
| | 113 |
| | 111 |
| | 769 |
|
Operating leases(b) | 96 |
| | 14 |
| | 25 |
| | 22 |
| | 35 |
|
Fuel purchase agreements(c) | 284 |
| | 30 |
| | 61 |
| | 64 |
| | 129 |
|
Long-term renewable energy and associated REC commitments(c) | 341 |
| | 31 |
| | 62 |
| | 62 |
| | 186 |
|
Electric supply procurement(c) | 458 |
| | 282 |
| | 176 |
| | — |
| | — |
|
Curtailment services commitments(c) | 31 |
| | 12 |
| | 15 |
| | 4 |
| | — |
|
Other purchase obligations(d) | 266 |
| | 187 |
| | 77 |
| | 1 |
| | 1 |
|
PJM regional transmission expansion commitments(e) | 9 |
| | 3 |
| | 3 |
| | 3 |
| | — |
|
| Total contractual obligations | $ | 4,039 |
| | $ | 707 |
| | $ | 532 |
| | $ | 767 |
| | $ | 2,033 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| |
(b) | Includes amounts related to shared use land arrangements. |
| |
(c) | Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric supply, and curtailment services. |
| |
(d) | Represents the future estimated value at December 31, 2018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(e) | Under its operating agreement with PJM, DPL is committed to the construction of transmission facilities to maintain system reliability. These amounts represent DPL’s expected portion of the costs to pay for the completion of the required construction projects. |
ACE
|
| | | | | | | | | | | | | | | | | | | |
| | | | Payment due within | | |
| | Total | | 2019 | | 2020 -
2021 | | 2022 -
2023 | | Due 2024
and beyond |
| Long-term debt | $ | 1,196 |
| | $ | 18 |
| | $ | 280 |
| | $ | — |
| | $ | 898 |
|
Interest payments on long-term debt (a) | 465 |
| | 52 |
| | 95 |
| | 81 |
| | 237 |
|
Operating leases(b) | 32 |
| | 7 |
| | 11 |
| | 9 |
| | 5 |
|
Electric supply procurement (c) | 514 |
| | 304 |
| | 210 |
| | — |
| | — |
|
Curtailment services commitments (c) | 4 |
| | 3 |
| | 1 |
| | — |
| | — |
|
Other purchase obligations (d) | 177 |
| | 160 |
| | 16 |
| | 1 |
| | — |
|
PJM regional transmission expansion commitments (e) | 68 |
| | 36 |
| | 26 |
| | 6 |
| | — |
|
| Total contractual obligations | $ | 2,456 |
| | $ | 580 |
| | $ | 639 |
| | $ | 97 |
| | $ | 1,140 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| |
(b) | Includes amounts related to shared use land arrangements. |
| |
(c) | Represents commitments to procure electric supply and curtailment services. |
| |
(d) | Represents the future estimated value at December 31, 2018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(e) | Under its operating agreement with PJM, ACE is committed to the construction of transmission facilities to maintain system reliability. These amounts represent ACE’s expected portion of the costs to pay for the completion of the required construction projects. |
See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ other commitments potentially triggered by future events.
For Additionally, see below for where to find additional information regarding:regarding certain contractual obligations in the Combined Notes to the Consolidated Financial Statements:
commercial paper, see Note 13 | | | | | |
| Item | Location within Notes to the Consolidated Financial Statements |
| Long-term debt | Note 17 — Debt and Credit Agreements |
| Interest payments on long-term debt | Note 17 — Debt and Credit Agreements |
| Finance leases | Note 11 — Leases |
| Operating leases | Note 11 — Leases |
| SNF obligation | Note 19 — Commitments and Contingencies |
| REC commitments | Note 3 — Regulatory Matters |
| ZEC commitments | Note 3 — Regulatory Matters |
| DC PLUG obligation | Note 3 — Regulatory Matters |
| Pension contributions | Note 15 — Retirement Benefits |
Sales of Customer Accounts Receivable
On April 8, 2020, Generation entered into an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain receivables, which expires on April 7, 2021 unless renewed by the mutual consent of the parties in accordance with its terms. The facility allows Generation to obtain financing at lower cost and diversify its sources of liquidity. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements.Statements for additional information.
long-term debt, see Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.
liabilities related to uncertain tax positions, see Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements.
capital lease obligations, see Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.
operating leases and rate relief commitments, see Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
the nuclear decommissioning and SNF obligations, see Note 15 — Asset Retirement Obligations and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
regulatory commitments, see Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.
variable interest entities, see Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements.
nuclear insurance, see Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
new accounting pronouncements, see Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements.
|
| | | | |
| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer, and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities.
Commodity Price Risk (All Registrants)
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the total amount of energy Exelon generates and purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel, and other commodities.
Generation
Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants' retail load, is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards, and options, with approved counterparties to hedge anticipated exposures. Generation uses derivative instruments as economic hedges to mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 20192021 through 2021.2023.
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Exelon's hedging program involves the hedging of commodity price risk for Exelon's expected generation, typically on a ratable basis over three-year periods. As of December 31, 2018,2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 89%-92%, 56%-59% and 32%-35%94%-97% for 2019, 2020 and 2021, respectively.2021. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilitiesgeneration based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts, including Generation’s sales to ComEd, PECO, BGE, Pepco, DPL, and BGEACE to serve their retail load.
A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire economic hedge portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on December 31, 20182020 market conditions and hedged position would be decreasesa decrease in pre-tax net income of approximately $57$15 million $383 million and $618 million, respectively, for 2019, 2020 and 2021. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation actively manages its portfolio to mitigate market price risk exposure for its unhedged position. Actual
results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio. See Note 1216 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Proprietary Trading Activities
Proprietary trading portfolio activity for the year ended December 31, 2018, resulted in pre-tax gains of $42 million due to net mark-to-market gains of $17 million and realized gains of $25 million. Generation has not segregated proprietary trading activity within the following discussion because of the relative size of the proprietary trading portfolio in comparison to Generation’s total Revenue net of purchased power and fuel expense. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Fuel Procurement
Generation procures natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 62%60% of Generation’s uranium concentrate requirements from 20192021 through 20232025 are supplied by three producers.suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s financial statements.
Utility Registrants
ComEd entered into 20-year contracts forfloating-to-fixed renewable energy and RECsswap contracts beginning in June 2012. ComEd is permitted2012, which are considered an economic hedge and have changes in fair value recorded to recover its renewable energy and REC costs from retail customers with no mark-up. The annual commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014.
an offsetting regulatory asset or liability. ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which is further discussed in Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. The block energy contracts are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance,NPNS, and as a result are accounted for on an accrual basis of accounting. ComEd does not execute derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
PECO, BGE, Pepco, DPL and ACE
PECO, BGE, Pepco, DPL, and ACE have contracts to procure electric supply that are executed through a competitive procurement process, which are further discussed in Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. PECO,process. BGE, Pepco, DPL, and ACE have certain full requirements contracts, which are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance,NPNS, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.
PECO, BGE, and DPL also have also executed derivative natural gas contracts, which either qualify for the normal purchases and normal sales exceptionNPNS or have no mark-to-market balances because the derivatives are index priced, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their financial statements.
PECO, BGE, Pepco, DPL, and ACE do not execute derivatives for speculative or proprietary trading purposes.
For additional information on these contracts, see Note 123 — Regulatory Matters and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
Trading and Non-Trading Marketing Activities
The following table detailing Exelon’s, Generation’s, and ComEd’s trading and non-trading marketing activities are included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).
The following table provides detail on changes in Exelon’s, Generation’s, and ComEd’s commodity mark-to-market net asset or liability balance sheet position from December 31, 20162018 to December 31, 2018.2020. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all NPNS contracts and does not segregate proprietary trading activity. See Note 1216 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 20182020 and 2017.2019.
| | | | | | | | | | Exelon | | Generation | | ComEd | |
Total mark-to-market energy contract net assets (liabilities) at December 31, 2018(a) | | Total mark-to-market energy contract net assets (liabilities) at December 31, 2018(a) | $ | 299 | | | $ | 548 | | | $ | (249) | | |
| Total change in fair value during 2019 of contracts recorded in result of operations | | Total change in fair value during 2019 of contracts recorded in result of operations | (427) | | | (427) | | | — | | |
| Reclassification to realized at settlement of contracts recorded in results of operations | | Reclassification to realized at settlement of contracts recorded in results of operations | 226 | | | 226 | | | — | | |
| | Exelon | | Generation | | ComEd | |
Total mark-to-market energy contract net assets (liabilities) at December 31, 2016(a) | $ | 719 |
|
| $ | 977 |
| | $ | (258 | ) | |
| Total change in fair value during 2017 of contracts recorded in result of operations | 110 |
| | 110 |
| | — |
| |
| Reclassification to realized at settlement of contracts recorded in results of operations | (273 | ) | | (273 | ) | | — |
| |
Changes in fair value—recorded through regulatory assets and liabilities(b) | (1 | ) | | — |
| | 2 |
| |
Changes in fair value—recorded through regulatory assets(b) | | Changes in fair value—recorded through regulatory assets(b) | (52) | | | — | | | (52) | | |
| Changes in allocated collateral | 140 |
| | 137 |
| | — |
| Changes in allocated collateral | 572 | | | 572 | | | — | | |
| Net option premium received | (28 | ) | | (28 | ) | | — |
| Net option premium received | 29 | | | 29 | | | — | | |
| Option premium amortization | (7 | ) | | (7 | ) | | — |
| Option premium amortization | (22) | | | (22) | | | — | | |
Upfront payments and amortizations(c) | (24 | ) | | (24 | ) | | — |
| Upfront payments and amortizations(c) | (58) | | | (58) | | | — | | |
Other miscellaneous(d) | 31 |
| | 31 |
| | — |
| |
Total mark-to-market energy contract net assets (liabilities) at December 31, 2017(a) | 667 |
| | 923 |
| | (256 | ) | |
| Total change in fair value during 2018 of contracts recorded in result of operations | 270 |
| | 270 |
| | — |
| |
| Total mark-to-market energy contract net assets (liabilities) at December 31, 2019(a) | | Total mark-to-market energy contract net assets (liabilities) at December 31, 2019(a) | 567 | | | 868 | | | (301) | | |
| Total change in fair value during 2020 of contracts recorded in result of operations | | Total change in fair value during 2020 of contracts recorded in result of operations | (203) | | | (203) | | | — | | |
| Reclassification to realized at settlement of contracts recorded in results of operations | (570 | ) | | (570 | ) | | — |
| Reclassification to realized at settlement of contracts recorded in results of operations | 469 | | | 469 | | | — | | |
Contracts received at acquisition date(e) | (19 | ) | | (19 | ) | | — |
| |
Changes in fair value—recorded through regulatory assets and liabilities(b) | 8 |
| | — |
| | 7 |
| |
| | Changes in allocated collateral | (110 | ) | | (109 | ) | | — |
| Changes in allocated collateral | (513) | | | (513) | | | — | | |
| Net option premium paid | 43 |
| | 43 |
| | — |
| Net option premium paid | 139 | | | 139 | | | — | | |
| Option premium amortization | (10 | ) | | (10 | ) | | — |
| Option premium amortization | (104) | | | (104) | | | — | | |
Upfront payments and amortizations(c) | 20 |
| | 20 |
| | — |
| Upfront payments and amortizations(c) | 73 | | | 73 | | | — | | |
Total mark-to-market energy contract net assets (liabilities) at December 31, 2018(a) | $ | 299 |
| | $ | 548 |
| | $ | (249 | ) | |
| Total mark-to-market energy contract net assets (liabilities) at December 31, 2020(a) | | Total mark-to-market energy contract net assets (liabilities) at December 31, 2020(a) | $ | 428 | | | $ | 729 | | | $ | (301) | | |
__________
| |
(a) | Amounts are shown net of collateral paid to and received from counterparties. |
| |
(b) | For ComEd, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2017 and 2018, ComEd recorded a regulatory liability of $256 million and $249 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. ComEd recorded $18(a)Amounts are shown net of collateral paid to and received from counterparties. (b)For ComEd, the changes in fair value are recorded as a change in regulatory assets. As of December 31, 2019 and 2020, ComEd recorded a regulatory liability of $301 million and $301 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. ComEd recorded $78 million of decreases in fair value and an increase for realized losses due to settlements of $20 million in purchased power expense associated with floating-to-fixed energy swap suppliers for the year ended December 31, 2017. ComEd recorded $24 million of decreases in fair value |
and realized losses due to settlements of $17$26 million in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2019. ComEd recorded $33 million of decrease in fair value and an increase for realized losses due to settlements of $33 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2018.2020.
| |
(c) | Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations. |
| |
(d) | As a result of the bankruptcy filing for EGTP on November 7, 2017, the net mark-to-market commodity contracts were deconsolidated from Exelon's and Generation's consolidated financial statements. |
| |
(e) | Includes fair value from contracts received at acquisition of the Everett Marine Terminal. |
(c)Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.
Fair Values
The following tables present maturity and source of fair value for Exelon, Generation, and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants’ commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 1118 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.
Exelon
| | | | Maturities Within | | Total Fair Value | | Maturities Within | | Total Fair
Value |
| | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and Beyond | | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 and Beyond | |
Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | | Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | |
| Actively quoted prices (Level 1) | $ | (11 | ) | | $ | (33 | ) | | $ | (6 | ) | | $ | (8 | ) | | $ | 14 |
| | $ | — |
| | $ | (44 | ) | Actively quoted prices (Level 1) | $ | (48) | | | $ | 8 | | | $ | 8 | | | $ | 11 | | | $ | 17 | | | $ | — | | | $ | (4) | |
| Prices provided by external sources (Level 2) | 45 |
| | (33 | ) | | 5 |
| | — |
| | — |
| | — |
| | 17 |
| Prices provided by external sources (Level 2) | 212 | | | 78 | | | 13 | | | (1) | | | 1 | | | — | | | 303 | |
Prices based on model or other valuation methods (Level 3)(c) | 291 |
| | 174 |
| | — |
| | (63 | ) | | (23 | ) | | (53 | ) | | 326 |
| Prices based on model or other valuation methods (Level 3)(c) | 182 | | | 80 | | | 47 | | | (7) | | | (16) | | | (157) | | | 129 | |
| Total | $ | 325 |
| | $ | 108 |
| | $ | (1 | ) | | $ | (71 | ) | | $ | (9 | ) | | $ | (53 | ) | | $ | 299 |
| Total | $ | 346 | | | $ | 166 | | | $ | 68 | | | $ | 3 | | | $ | 2 | | | $ | (157) | | | $ | 428 | |
__________
| |
(a) | Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations. |
| |
(b) | Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $357 million at December 31, 2018. |
| |
(c) | Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers. |
(a)Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.
(b)Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $416 million at December 31, 2020.
(c)Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Generation
| | | | Maturities Within | | Total Fair Value | | Maturities Within | | Total Fair
Value |
| | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and Beyond | | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 and Beyond | |
Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | | Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | |
| Actively quoted prices (Level 1) | $ | (11 | ) | | $ | (33 | ) | | $ | (6 | ) | | $ | (8 | ) | | $ | 14 |
| | $ | — |
| | $ | (44 | ) | Actively quoted prices (Level 1) | $ | (48) | | | $ | 8 | | | $ | 8 | | | $ | 11 | | | $ | 17 | | | $ | — | | | $ | (4) | |
| Prices provided by external sources (Level 2) | 45 |
| | (33 | ) | | 5 |
| | — |
| | — |
| | — |
| | 17 |
| Prices provided by external sources (Level 2) | 212 | | | 78 | | | 13 | | | (1) | | | 1 | | | — | | | 303 | |
Prices based on model or other valuation methods (Level 3)(c) | 317 |
| | 199 |
| | 25 |
| | (37 | ) | | 3 |
| | 68 |
| | 575 |
| |
| Prices based on model or other valuation methods (Level 3) | | Prices based on model or other valuation methods (Level 3) | 215 | | | 109 | | | 75 | | | 20 | | | 10 | | | 1 | | | 430 | |
| Total | $ | 351 |
| | $ | 133 |
| | $ | 24 |
| | $ | (45 | ) | | $ | 17 |
| | $ | 68 |
| | $ | 548 |
| Total | $ | 379 | | | $ | 195 | | | $ | 96 | | | $ | 30 | | | $ | 28 | | | $ | 1 | | | $ | 729 | |
__________
| |
(a) | Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations. |
| |
(b) | Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $357 million at December 31, 2018. |
(a)Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.
(b)Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $416 million at December 31, 2020.
ComEd
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Maturities Within | | Fair Value |
| | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and Beyond | |
Prices based on model or other valuation methods (Level 3)(a) | $ | (26 | ) | | $ | (25 | ) | | $ | (25 | ) | | $ | (26 | ) | | $ | (26 | ) | | $ | (121 | ) | | $ | (249 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Maturities Within | | Total Fair
Value |
| 2021 | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 and Beyond | |
Commodity derivative contracts(a): | | | | | | | | | | | | | |
Prices based on model or other valuation methods (Level 3)(a) | $ | (33) | | | $ | (29) | | | $ | (28) | | | $ | (27) | | | $ | (26) | | | $ | (158) | | | $ | (301) | |
__________
| |
(a) | Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers. |
(a)Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Credit Risk Collateral and Contingent Related Features (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 12—16—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk, collateral, and contingent related features.risk.
Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchases and normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2018.2020. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the tablestable below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs, and commodity exchanges, which are discussed below. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $43 million, $30 million, $24 million, $28 million, $7 million and $5 million respectively. See Note 25 — Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Rating as of December 31, 2020 | Total
Exposure
Before Credit
Collateral | | Credit
Collateral(a) | | Net
Exposure | | Number of
Counterparties
Greater than 10%
of Net Exposure | | Net Exposure of
Counterparties
Greater than 10%
of Net Exposure |
| Investment grade | $ | 577 | | | $ | 27 | | | $ | 550 | | | — | | | $ | — | |
| Non-investment grade | 32 | | | — | | | 32 | | | — | | | — | |
| No external ratings | | | | | | | | | |
| Internally rated—investment grade | 165 | | | 1 | | | 164 | | | — | | | — | |
| Internally rated—non-investment grade | 80 | | | 28 | | | 52 | | | — | | | — | |
| Total | $ | 854 | | | $ | 56 | | | $ | 798 | | | — | | | $ | — | |
| | | | | | | | | | | | | | Maturity of Credit Risk Exposure |
| Rating as of December 31, 2018 | Total Exposure Before Credit Collateral | | Credit
Collateral (a) | | Net Exposure | | Number of Counterparties Greater than 10% of Net Exposure | | Net Exposure of Counterparties Greater than 10% of Net Exposure | |
| Rating as of December 31, 2020 | | Rating as of December 31, 2020 | Less than
2 Years | | 2-5
Years | | Exposure
Greater than
5 Years | | Total Exposure
Before Credit
Collateral |
| Investment grade | $ | 795 |
| | $ | — |
| | $ | 795 |
| | 1 |
| | $ | 153 |
| Investment grade | $ | 520 | | | $ | 36 | | | $ | 21 | | | $ | 577 | |
| Non-investment grade | 133 |
| | 45 |
| | 88 |
| | — |
| | — |
| Non-investment grade | 32 | | | — | | | — | | | 32 | |
| No external ratings | | | | | | | | | | No external ratings | |
| Internally rated—investment grade | 181 |
| | 1 |
| | 180 |
| | — |
| | — |
| Internally rated—investment grade | 128 | | | 25 | | | 12 | | | 165 | |
| Internally rated—non-investment grade | 92 |
| | 6 |
| | 86 |
| | — |
| | — |
| Internally rated—non-investment grade | 67 | | | 10 | | | 3 | | | 80 | |
| Total | $ | 1,201 |
| | $ | 52 |
| | $ | 1,149 |
| | 1 |
| | $ | 153 |
| Total | $ | 747 | | | $ | 71 | | | $ | 36 | | | $ | 854 | |
|
| | | | | | | | | | | | | | | |
| | Maturity of Credit Risk Exposure |
| Rating as of December 31, 2018 | Less than 2 Years | | 2-5 Years | | Exposure Greater than 5 Years | | Total Exposure Before Credit Collateral |
| Investment grade | $ | 755 |
| | $ | 23 |
| | $ | 17 |
| | $ | 795 |
|
| Non-investment grade | 131 |
| | 2 |
| | — |
| | 133 |
|
| No external ratings | | | | | | | |
| Internally rated—investment grade | 126 |
| | 26 |
| | 29 |
| | 181 |
|
| Internally rated—non-investment grade | 82 |
| | 5 |
| | 5 |
| | 92 |
|
| Total | $ | 1,094 |
| | $ | 56 |
| | $ | 51 |
| | $ | 1,201 |
|
|
| | | |
| Net Credit Exposure by Type of Counterparty | As of December 31, 2018 |
| Financial institutions | $ | 12 |
|
| Investor-owned utilities, marketers, power producers | 737 |
|
| Energy cooperatives and municipalities | 324 |
|
| Other | 76 |
|
| Total | $ | 1,149 |
|
__________
| | | | | |
(a)Net Credit Exposure by Type of Counterparty | As of December 31, 2018, credit collateral held from counterparties where Generation had credit exposure included $17 million of cash2020 |
| Financial institutions | $ | 15 | |
| Investor-owned utilities, marketers, power producers | 607 | |
Energy cooperatives and $35 million of letters of credit.municipalities | 138 | |
| Other | 38 | |
| Total | $ | 798 | |
__________
(a)As of December 31, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $25 million of letters of credit.
The Utility Registrants
Credit risk for the Utility Registrants is governed by credit and collection policies, which are aligned with state regulatory requirements. The Utility Registrants are currently obligated to provide service to all electric customers within their franchised territories. The Utility Registrants record a provisionan allowance for uncollectible accounts,credit losses on customer receivables, based upon historical loss experience, current conditions, and forward-looking risk factors, to provide for the potential loss from nonpayment by these customers. The Utility Registrants will monitor nonpayment from customers and will make any necessary adjustments to the provisionallowance for uncollectible accounts.credit losses on customer receivables. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for the allowance for uncollectible accountscredit losses policy. The Utility Registrants did not have any customers representing over 10% of their revenues as of December 31, 2018.2020. See Note 43 — Regulatory Matters of the
Combined Notes to Consolidated Financial Statements for additional information.information regarding the regulatory recovery of credit losses on customer accounts receivable.
As of December 31, 2018, ComEd, PECO, BGE, Pepco, DPL and ACE's2020, the Utility Registrants net credit exposure to suppliers was immaterial. See Note 1216 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
CollateralCredit-Risk-Related Contingent Features (All Registrants)
Generation
As part of the normal course of business, Generation routinely enters into physical or financial contracts for the sale and purchase of electricity, natural gas, and other commodities. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. See Note 1216 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements. Seerequirements and Note 2219 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.
Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these
payments from counterparties could have a material impact on Exelon’s and Generation’s financial statements. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. To post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 7. Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities for additional information.
The Utility Registrants
As of December 31, 2018, ComEd held $38 million in collateral from suppliers in association with energy procurement contracts, approximately $31 million in collateral from suppliers for REC contract obligations and approximately $19 million in collateral from suppliers for long-term renewable energy contracts. BGE is not required to post collateral under its electric supply contracts but was holding an immaterial amount of collateral under its electric supply procurement contracts. BGE was not required to post collateral under its natural gas procurement contracts, but was holding an immaterial amount of collateral under its natural gas procurement contracts. Pepco and DPL were not required to post collateral under their energy and/or natural gas procurement contracts, but were holding an immaterial amount of collateral under their respective electric supply procurement contracts. PECO and ACE2020, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 43 — Regulatory Matters and Note 1216 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
RTOs and ISOs (All Registrants)
All Registrants participate in all, or some, of the established, wholesale spot energy markets that are administered by PJM, ISO-NE, ISO-NY,NYISO, CAISO, MISO, SPP, AESO, OIESO, and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no spot energy market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ financial statements.
Exchange Traded Transactions (Exelon, Generation, PHI, and DPL)
Generation enters into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange ("the Exchanges"). DPL enters into commodity transactions on ICE. The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk.
Interest Rate and Foreign Exchange Risk (All Registrants)(Exelon and Generation)
The RegistrantsExelon and Generation use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The RegistrantsExelon and Generation may also utilize interest rate swaps to manage their interest rate exposure. At December 31, 2018, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon and Generation had $622 million of notional amounts of floating-to-fixed hedges outstanding. A hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $6$2 million decrease in Exelon Consolidated pre-tax income for the year ended December 31, 2018.2020. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. See Note 12—16—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Equity Price Risk (Exelon and Generation)
Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of December 31, 2018,2020, Generation’s NDT funds are reflected at fair value in its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment policy. A hypothetical 10%25 basis points increase in interest rates and 10% decrease in equity prices would result in a $529$851 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Liquidity and Capital Resources section of ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information of equity price risk as a result of the current capital and credit market conditions.
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Generation
General
Generation’s integrated business consists of the generation, physical delivery, and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services. Generation has sixfive reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT, and Other Power Regions. These segments are discussed in further detail in ITEM 1. BUSINESS — Exelon Generation Company, LLC of this Form 10-K.
Executive Overview
A discussion of items pertinent to Generation’s executive overview is set forth under ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Exelon Corporation — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 20162019
A discussion of Generation’s results of operations for 20182020 compared to 2017 and 2017 compared to 20162019 is set forth under Results of Operations—Generation in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, participation in the intercompany money pool, or capital contributions from Exelon. Generation’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Generation no longer has access to the capital markets at reasonable terms, Generation has credit facilities in the aggregate of $5.3 billion that currently support its commercial paper program and issuances of letters of credit.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 1317 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund Generation’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefitOPEB obligations, and invest in new and existing ventures. Generation spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment.
Cash Flows from Operating Activities
A discussion of items pertinent to Generation’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to Generation’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to Generation’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to Generation is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of Generation’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of Generation’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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| | | | |
| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Generation
Generation is exposed to market risks associated with commodity price, credit, interest rates, and equity price. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk — Exelon.
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
ComEd
General
ComEd operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in northern Illinois, including the City of Chicago. This segment is discussed in further detail in ITEM 1. BUSINESS—ComEd of this Form 10-K.
Executive Overview
A discussion of items pertinent to ComEd’s executive overview is set forth under EXELON CORPORATION—Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 20162019
A discussion of ComEd’s results of operations for 20182020 compared to 2017 and for 2017 compared to 20162019 is set forth under Results of Operations—ComEd in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, or credit facility borrowings. ComEd’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2018,2020, ComEd had access to a revolving credit facility with aggregate bank commitments of $1 billion.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 1317 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund ComEd’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefitOPEB obligations, and invest in new and existing ventures. ComEd spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to ComEd’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to ComEd’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to ComEd’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to ComEd is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of ComEd’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of ComEd’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ComEd
ComEd is exposed to market risks associated with commodity price credit and interest rates.credit. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk— Exelon.
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
PECO
General
PECO operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution service in Pennsylvania in the counties surrounding the City of Philadelphia. This segment is discussed in further detail in ITEM 1. BUSINESS—PECO of this Form 10-K.
Executive Overview
A discussion of items pertinent to PECO’s executive overview is set forth under EXELON CORPORATION—Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 2019
A discussion of PECO’s results of operations for 20182020 compared to 2017 and for 2017 compared to 20162019 is set forth under Results of Operations—PECO in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, or participation in the intercompany money pool. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to the capital markets at reasonable terms, PECO has access to a revolving credit facility. At December 31, 2018,2020, PECO had access to a revolving credit facility with aggregate bank commitments of $600 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 1317 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund PECO’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefitOPEB obligations, and invest in new and existing ventures. PECO spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, PECO operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to PECO’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to PECO is set forth under Credit Matters in “EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of PECO’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of PECO’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
PECO
PECO is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
BGE
General
BGE operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution service in central Maryland, including the City of Baltimore. This segment is discussed in further detail in ITEM 1. BUSINESS—BGE of this Form 10-K.
Executive Overview
A discussion of items pertinent to BGE’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 20162019
A discussion of BGE’s results of operations for 20182020 compared to 2017 and for 2017 compared to 20162019 is set forth under Results of Operations—BGE in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
BGE’s business is capital intensive and requires considerable capital resources. BGE’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper. BGE’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where BGE no longer has access to the capital markets at reasonable terms, BGE has access to a revolving credit facility. At December 31, 2018,2020, BGE had access to a revolving credit facility with aggregate bank commitments of $600 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 1317 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund BGE’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefitOPEB obligations, and invest in new and existing ventures. BGE spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, BGE operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to BGE’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to BGE’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to BGE’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to BGE is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of BGE’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of BGE’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
BGE
BGE is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
PHI
General
PHI has three reportable segments Pepco, DPL, and ACE. Its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services, and to a lesser extent, the purchase and regulated retail sale and supply of natural gas in Delaware. This segment is discussed in further detail in ITEM 1. BUSINESS — PHI of this Form 10-K.
Executive Overview
A discussion of items pertinent to PHI’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Successor Period Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017, Successor Period of March 24, 2016 to December 31, 2016 and Predecessor Period of January 1, 2016 to March 23, 20162019
A discussion of PHI’s results of operations for 20182020 compared to 2017, March 24, 2016 to December 31, 2016 and January 1, 2016 to March 23, 20162019 is set forth under Results of Operations—PHI in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
PHI’s business is capital intensive and requires considerable capital resources. PHI’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper, borrowings from the Exelon money pool, or capital contributions from Exelon. PHI’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 1317 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund PHI’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefitOPEB obligations, and invest in new and existing ventures. PHI spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment.
Cash Flows from Operating Activities
A discussion of items pertinent to PHI’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to PHI’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to PHI’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to PHI is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of PHI’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of PHI’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
PHI
PHI is exposed to market risks associated with commodity price, credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk — Exelon.
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Pepco
General
Pepco operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. This segment is discussed in further detail in ITEM 1. BUSINESS — Pepco of this Form 10-K.
Executive Overview
A discussion of items pertinent to Pepco’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 20162019
A discussion of Pepco’s results of operations for 20182020 compared to 2017 and for 2017 compared to 20162019 is set forth under Results of Operations—Pepco in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
Pepco’s business is capital intensive and requires considerable capital resources. Pepco’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, or credit facility borrowings. Pepco’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2018,2020, Pepco had access to a revolving credit facility with aggregate bank commitments of $300 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 1317 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund Pepco’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefitOPEB obligations, and invest in new and existing ventures. Pepco spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, Pepco operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to Pepco’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to Pepco’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to Pepco’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to Pepco is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of Pepco’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of Pepco’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Pepco
Pepco is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk— Exelon.
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
DPL
General
DPL operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale and supply of natural gas in New Castle County, Delaware. This segment is discussed in further detail in ITEM 1. BUSINESS — DPL of this Form 10-K.
Executive Overview
A discussion of items pertinent to DPL’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 20162019
A discussion of DPL’s results of operations for 20182020 compared to 2017 and for 2017 compared to 20162019 is set forth under Results of Operations—DPL in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
DPL’s business is capital intensive and requires considerable capital resources. DPL’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper. DPL’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where DPL no longer has access to the capital markets at reasonable terms, DPL has access to a revolving credit facility. At December 31, 2018,2020, DPL had access to a revolving credit facility with aggregate bank commitments of $300 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 1317 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund DPL’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefitOPEB obligations, and invest in new and existing ventures. DPL spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, DPL operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to DPL’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to DPL’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to DPL’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to DPL is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of DPL’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of DPL’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
DPL
DPL is exposed to market risks associated with commodity price, credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
ACE
General
ACE operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in portions of southern New Jersey. This segment is discussed in further detail in ITEM 1. BUSINESS — ACE of this Form 10-K.
Executive Overview
A discussion of items pertinent to ACE’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 20182020 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 20162019
A discussion of ACE’s results of operations for 20182020 compared to 2017 and for 2017 compared to 20162019 is set forth under Results of Operations—ACE in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
ACE’s business is capital intensive and requires considerable capital resources. ACE’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, or credit facility borrowings. ACE’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2018,2020, ACE had access to a revolving credit facility with aggregate bank commitments of $300 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 1317 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund ACE’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefitOPEB obligations, and invest in new and existing ventures. ACE spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ACE operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to ACE’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to ACE’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to ACE’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to ACE is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of ACE’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of ACE’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ACE
ACE is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk— Exelon.
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| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Management’s Report on Internal Control Over Financial Reporting
The management of Exelon Corporation (Exelon) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Exelon’s management conducted an assessment of the effectiveness of Exelon’s internal control over financial reporting as of December 31, 2018.2020. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Exelon’s management concluded that, as of December 31, 2018,2020, Exelon’s internal control over financial reporting was effective.
The effectiveness of Exelon’s internal control over financial reporting as of December 31, 2018,2020, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 8, 201924, 2021
Management’s Report on Internal Control Over Financial Reporting
The management of Exelon Generation Company, LLC (Generation) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Generation’s management conducted an assessment of the effectiveness of Generation’s internal control over financial reporting as of December 31, 2018.2020. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Generation’s management concluded that, as of December 31, 2018,2020, Generation’s internal control over financial reporting was effective.
The effectiveness of Generation’s internal control over financial reporting as of December 31, 2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 8, 201924, 2021
Management’s Report on Internal Control Over Financial Reporting
The management of Commonwealth Edison Company (ComEd) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
ComEd’s management conducted an assessment of the effectiveness of ComEd’s internal control over financial reporting as of December 31, 2018.2020. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, ComEd’s management concluded that, as of December 31, 2018,2020, ComEd’s internal control over financial reporting was effective.
The effectiveness of ComEd’s internal control over financial reporting as of December 31, 2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 8, 201924, 2021
Management’s Report on Internal Control Over Financial Reporting
The management of PECO Energy Company (PECO) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PECO’s management conducted an assessment of the effectiveness of PECO’s internal control over financial reporting as of December 31, 2018.2020. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, PECO’s management concluded that, as of December 31, 2018,2020, PECO’s internal control over financial reporting was effective.
The effectiveness of PECO’s internal control over financial reporting as of December 31, 2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 8, 201924, 2021
Management’s Report on Internal Control Over Financial Reporting
The management of Baltimore Gas and Electric Company (BGE) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
BGE’s management conducted an assessment of the effectiveness of BGE’s internal control over financial reporting as of December 31, 2018.2020. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, BGE’s management concluded that, as of December 31, 2018,2020, BGE’s internal control over financial reporting was effective.
The effectiveness of BGE’s internal control over financial reporting as of December 31, 2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 8, 201924, 2021
Management’s Report on Internal Control Over Financial Reporting
The management of Pepco Holdings LLC (PHI) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PHI’s management conducted an assessment of the effectiveness of PHI’s internal control over financial reporting as of December 31, 2018.2020. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, PHI’s management concluded that, as of December 31, 2018,2020, PHI’s internal control over financial reporting was effective.
The effectiveness of PHI’s internal control over financial reporting as of December 31, 2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 8, 201924, 2021
Management’s Report on Internal Control Over Financial Reporting
The management of Potomac Electric Power Company (Pepco) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Pepco’s management conducted an assessment of the effectiveness of Pepco’s internal control over financial reporting as of December 31, 2018.2020. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Pepco’s management concluded that, as of December 31, 2018,2020, Pepco’s internal control over financial reporting was effective.
February 8, 201924, 2021
Management’s Report on Internal Control Over Financial Reporting
The management of Delmarva Power & Light Company (DPL) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
DPL’s management conducted an assessment of the effectiveness of DPL’s internal control over financial reporting as of December 31, 2018.2020. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, DPL’s management concluded that, as of December 31, 2018,2020, DPL’s internal control over financial reporting was effective.
February 8, 201924, 2021
Management’s Report on Internal Control Over Financial Reporting
The management of Atlantic City Electric Company (ACE) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
ACE’s management conducted an assessment of the effectiveness of ACE’s internal control over financial reporting as of December 31, 2018.2020. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, ACE’s management concluded that, as of December 31, 2018,2020, ACE’s internal control over financial reporting was effective.
February 8, 201924, 2021
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Shareholders of Exelon Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(i), and the financial statement schedules listed in the index appearing under Item 15(a)(1)(ii), of Exelon Corporation and its subsidiaries (the "Company"“Company”) (collectively referred to as the “consolidated financial statements”).We also have audited the Company's internal control over financial reporting as of December 31, 2018,2020, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20182020 and 2017, 2019, and the results of itsoperations and itscash flows for each of the three years in the period ended December 31, 20182020 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018,2020, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.
Basis for OpinionsChange in Accounting Principle
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, includedAs discussed in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility isNote 1 to express opinions on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidatedfinancial statements included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 8, 2019
We have served as the Company’s auditor since 2000.
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Member of Exelon Generation Company, LLC
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(2)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(ii), of Exelon Generation Company, LLC and its subsidiaries (the "Company") (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, andchanged the results of itsoperations and itscash flowsmanner in which it accounts for each of the three yearsleases in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.2019.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidatedfinancial statements included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 8, 2019
We have served as the Company’s auditor since 2001.
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Shareholders of Commonwealth Edison Company
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(3)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(3)(ii), of Commonwealth Edison Company and its subsidiaries (the "Company") (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of itsoperations and itscash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidatedfinancial statements included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 8, 2019
We have served as the Company’s auditor since 2000.
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Shareholder of PECO Energy Company
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(4)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(4)(ii), of PECO Energy Company and its subsidiaries (the "Company") (collectively referred to as the “consolidated financial statements”).We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of itsoperations and itscash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidatedfinancial statements included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 8, 2019
We have served as the Company’s auditor since 1932.
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Shareholder of Baltimore Gas and Electric Company
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(5)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(5)(ii), of Baltimore Gas and Electric Company and its subsidiaries (the "Company") (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of itsoperations and itscash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidatedfinancial statements included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 8, 2019
We have served as the Company’s auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Member of Pepco Holdings LLC
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(6)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(6)(iii), of Pepco Holdings LLC and its subsidiaries (Successor) (the "Company") (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of itsoperations and itscash flows for each of the two years in the period ended December 31, 2018 and for the period from March 24, 2016 to December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidatedfinancial statements included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated beloware mattersarising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to theconsolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Annual Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment
As described in Notes 1 and 10 to the consolidated financial statements, the Company has a legal obligation to decommission its nuclear generation stations following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, management uses a probability-weighted cash flow model, which on a unit-by-unit basis, considers multiple scenarios that include significant estimates and assumptions such as decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Management updates its ARO annually unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. As of December 31, 2020, the nuclear decommissioning ARO was approximately $11.9 billion.
The principal considerations for our determination that performing procedures relating to the Company’s annual ARO assessment is a critical audit matter are the significant judgment by management when estimating its decommissioning obligation; this in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s cash flow model and significant assumptions related to decommissioning cost studies. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and model used in management’s ARO assessment. These procedures also included, among others, testing management’s process for developing the ARO estimates by evaluating the appropriateness of the cash flow model, testing the completeness and accuracy of data used by management, and evaluating the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge were used to assist in evaluating the results of decommissioning cost studies.
Impairment Assessment of Long-Lived Generation Assets
As described in Notes 1 and 12 to the consolidated financial statements, the Company evaluates the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. Management determines if long-lived assets and asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The expected future cash flows include significant unobservable inputs including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As of December 31, 2020, the total carrying value of long-lived generation assets subject to this evaluation was approximately $22.2 billion.
The principal considerations for our determination that performing procedures relating to the Company’s impairment assessment of long-lived generation assets is a critical audit matter are the significant judgment by management in assessing the recoverability of these asset groups; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating the reasonableness of management’s significant assumptions related to revenue and generation forecasts. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and model used to estimate the recoverability and fair value of the Company’s long-lived generation asset groups. These procedures also included, among others, testing management’s process for developing expected future cash flows for long-lived generation asset groups by evaluating the appropriateness of the future cash flow model, testing the completeness and accuracy of the data used by management, and evaluating the reasonableness of management’s significant assumptions related to revenue and generation forecasts. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of revenue forecasts.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. As of December 31, 2020, there were approximately $10.0 billion of regulatory assets and approximately $10.1 billion of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Washington, DCChicago, Illinois
February 8, 201924, 2021
We have served as the Company’s auditor since 2001.2000.
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Member of Pepco HoldingsExelon Generation Company, LLC
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(6)(ii) present fairly, in all material respects, the results of operations and cash flows of Pepco Holdings LLC and its subsidiaries (formerly Pepco Holdings, Inc.) (Predecessor) for the period January 1, 2016 to March 23, 2016 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the period January 1, 2016 to March 23, 2016 listed in the index appearing under Item 15(a)(6)(iv) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 13, 2017
Report of Independent Registered Public Accounting Firm
Tothe Board of Directors and Shareholder of Potomac Electric Power Company
Opinion on the Financial Statements
We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(7)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(7)(ii), of Potomac Electric Power Company (the "Company") (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
Thesefinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of thesefinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of thefinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in thefinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of thefinancial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 8, 2019
We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
Tothe Board of Directors and Shareholder of Delmarva Power & Light Company
Opinion on the Financial Statements
We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(8)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(8)(ii), of Delmarva Power & Light Company (the "Company") (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
Thesefinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of thesefinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of thefinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in thefinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of thefinancial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 8, 2019
We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
Tothe Board of Directors and Shareholder of Atlantic City Electric Company
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(9)(2)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(9)(2)(ii), of Atlantic City ElectricExelon Generation Company, LLC and its subsidiarysubsidiaries (the "Company"“Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 20182020 and 2017,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20182020in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
These consolidatedfinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of theseconsolidatedfinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in theconsolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of theconsolidatedfinancial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to theconsolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidatedfinancial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Annual Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment
As described in Notes 1 and 10 to the consolidated financial statements, the Company has a legal obligation to decommission its nuclear generation stations following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, management uses a probability-weighted cash flow model, which on a unit-by-unit basis, considers multiple scenarios that include significant estimates and assumptions such as decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Management updates its ARO annually
unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. As of December 31, 2020, the nuclear decommissioning ARO was approximately $11.9 billion.
The principal considerations for our determination that performing procedures relating to the Company’s annual ARO assessment is a critical audit matter are the significant judgment by management when estimating its decommissioning obligation; this in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s cash flow model and significant assumptions related to decommissioning cost studies. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and model used in management’s ARO assessment. These procedures also included, among others, testing management’s process for developing the ARO estimates by evaluating the appropriateness of the cash flow model, testing the completeness and accuracy of data used by management, and evaluating the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge were used to assist in evaluating the results of decommissioning cost studies.
Impairment Assessment of Long-Lived Generation Assets
As described in Notes 1 and 12 to the consolidated financial statements, the Company evaluates the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. Management determines if long-lived assets and asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The expected future cash flows include significant unobservable inputs including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As of December 31, 2020, the total carrying value of long-lived generation assets subject to this evaluation was approximately $22.2 billion.
The principal considerations for our determination that performing procedures relating to the Company’s impairment assessment of long-lived generation assets is a critical audit matter are the significant judgment by management in assessing the recoverability of these asset groups; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating the reasonableness of management’s significant assumptions related to revenue and generation forecasts. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and model used to estimate the recoverability and fair value of the Company’s long-lived generation asset groups. These procedures also included, among others, testing management’s process for developing expected future cash flows for long-lived generation asset groups by evaluating the appropriateness of the future cash flow model, testing the completeness and accuracy of the data used by management, and evaluating the reasonableness of management’s significant assumptions related to revenue and generation forecasts. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of revenue forecasts.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 24, 2021
We have served as the Company's auditor since 2001.
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Shareholders of Commonwealth Edison Company
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(3)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(3)(ii), of Commonwealth Edison Company and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of theseconsolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of theconsolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in theconsolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of theconsolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to theconsolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will
be recovered and settled, respectively, in future rates. As of December 31, 2020, there were approximately $2.0 billion of regulatory assets and approximately $6.7 billion of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 24, 2021
We have served as the Company's auditor since 2000.
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Shareholder of PECO Energy Company
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(4)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(4)(ii), of PECO Energy Company and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
Theseconsolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of theseconsolidatedfinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of theconsolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to theconsolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will
be recovered and settled, respectively, in future rates. As of December 31, 2020, there were approximately $801 million of regulatory assets and approximately $624 million of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Washington, DCPhiladelphia, Pennsylvania
February 8,24, 2021
We have served as the Company's auditor since 1932.
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Shareholder of Baltimore Gas and Electric Company
Opinion on the Financial Statements
We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(5)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(5)(ii), of Baltimore Gas and Electric Company (the “Company”) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
Thesefinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of thesefinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to thefinancial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in their financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in
accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. As of December 31, 2020, there were approximately $649 million of regulatory assets and approximately $1,139 million of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 24, 2021
We have served as the Company’s auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Member of Pepco Holdings LLC
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(6)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(6)(ii), of Pepco Holdings LLC and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
Theseconsolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of theseconsolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of theconsolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to theconsolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidatedfinancial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for
its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. As of December 31, 2020, there were approximately $2.4 billion of regulatory assets and approximately $1.6 billion of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 24, 2021
We have served as the Company's auditor since 2001.
Report of Independent Registered Public Accounting Firm
Tothe Board of Directors and Shareholder of Potomac Electric Power Company
Opinion on the Financial Statements
We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(7)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(7)(ii), of Potomac Electric Power Company (the “Company”) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
Thesefinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of thesefinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of thefinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in thefinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of thefinancial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to thefinancial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in their financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in
accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. As of December 31, 2020, there were approximately $784 million of regulatory assets and approximately $690 million of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 24, 2021
We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
Tothe Board of Directors and Shareholder of Delmarva Power & Light Company
Opinion on the Financial Statements
We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(8)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(8)(ii), of Delmarva Power & Light Company (the “Company”) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
Thesefinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of thesefinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of thefinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in thefinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of thefinancial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to thefinancial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in their financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in
accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. As of December 31, 2020, there were approximately $280 million of regulatory assets and approximately $540 million of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 24, 2021
We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
Tothe Board of Directors and Shareholder of Atlantic City Electric Company
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(9)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(9)(ii), of Atlantic City Electric Company and its subsidiary (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Companyas of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
These consolidatedfinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidatedfinancial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to theconsolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidatedfinancial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for
its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. As of December 31, 2020, there were approximately $470 million of regulatory assets and approximately $318 million of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 24, 2021
We have served as the Company's auditor since 1998.
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income | | | | For the Years Ended December 31, | | For the Years Ended December 31, |
| (In millions, except per share data) | 2018 | | 2017 | | 2016 | (In millions, except per share data) | 2020 | | 2019 | | 2018 |
| Operating revenues | | | | | | Operating revenues | | | | | |
| Competitive businesses revenues | $ | 19,168 |
| | $ | 17,394 |
| | $ | 16,330 |
| Competitive businesses revenues | $ | 16,400 | | | $ | 17,754 | | | $ | 19,168 | |
| Rate-regulated utility revenues | 16,879 |
| | 15,964 |
| | 14,988 |
| Rate-regulated utility revenues | 16,633 | | | 16,839 | | | 16,879 | |
| Revenues from alternative revenue programs | (62 | ) | | 207 |
| | 48 |
| Revenues from alternative revenue programs | 6 | | | (155) | | | (69) | |
| | Total operating revenues | 35,985 |
| | 33,565 |
| | 31,366 |
| Total operating revenues | 33,039 | | | 34,438 | | | 35,978 | |
| Operating expenses | | | | | | Operating expenses | | | | | |
| Competitive businesses purchased power and fuel | 11,679 |
| | 9,668 |
| | 8,817 |
| Competitive businesses purchased power and fuel | 9,592 | | | 10,849 | | | 11,679 | |
| Rate-regulated utility purchased power and fuel | 4,991 |
| | 4,367 |
| | 3,823 |
| Rate-regulated utility purchased power and fuel | 4,512 | | | 4,648 | | | 4,991 | |
| | Operating and maintenance | 9,337 |
| | 10,025 |
| | 9,954 |
| Operating and maintenance | 9,408 | | | 8,615 | | | 9,337 | |
| Depreciation and amortization | 4,353 |
| | 3,828 |
| | 3,936 |
| Depreciation and amortization | 5,014 | | | 4,252 | | | 4,353 | |
| Taxes other than income | 1,783 |
| | 1,731 |
| | 1,576 |
| |
| Taxes other than income taxes | | Taxes other than income taxes | 1,714 | | | 1,732 | | | 1,783 | |
| Total operating expenses | 32,143 |
|
| 29,619 |
|
| 28,106 |
| Total operating expenses | 30,240 | | | 30,096 | | | 32,143 | |
| Gain (loss) on sales of assets and businesses | 56 |
| | 3 |
| | (48 | ) | |
| Bargain purchase gain | — |
| | 233 |
| | — |
| |
| | Gain on sales of assets and businesses | | Gain on sales of assets and businesses | 24 | | | 31 | | | 56 | |
| | Gain on deconsolidation of business | — |
| | 213 |
| | — |
| Gain on deconsolidation of business | 0 | | | 1 | | | 0 | |
| Operating income | 3,898 |
|
| 4,395 |
|
| 3,212 |
| Operating income | 2,823 | | | 4,374 | | | 3,891 | |
| Other income and (deductions) | | | | | | Other income and (deductions) | | | | | |
| Interest expense, net | (1,529 | ) | | (1,524 | ) | | (1,495 | ) | Interest expense, net | (1,610) | | | (1,591) | | | (1,529) | |
| Interest expense to affiliates | (25 | ) | | (36 | ) | | (41 | ) | Interest expense to affiliates | (25) | | | (25) | | | (25) | |
| Other, net | (112 | ) | | 947 |
| | 297 |
| Other, net | 1,145 | | | 1,227 | | | (112) | |
| Total other income and (deductions) | (1,666 | ) |
| (613 | ) |
| (1,239 | ) | |
| Total other (deductions) | | Total other (deductions) | (490) | | | (389) | | | (1,666) | |
| Income before income taxes | 2,232 |
| | 3,782 |
| | 1,973 |
| Income before income taxes | 2,333 | | | 3,985 | | | 2,225 | |
| Income taxes | 120 |
| | (126 | ) | | 753 |
| Income taxes | 373 | | | 774 | | | 118 | |
| Equity in losses of unconsolidated affiliates | (28 | ) | | (32 | ) | | (24 | ) | Equity in losses of unconsolidated affiliates | (6) | | | (183) | | | (28) | |
| Net income | 2,084 |
|
| 3,876 |
|
| 1,196 |
| Net income | 1,954 | | | 3,028 | | | 2,079 | |
| Net income attributable to noncontrolling interests and preference stock dividends | 74 |
| | 90 |
| | 75 |
| |
| Net (loss) income attributable to noncontrolling interests | | Net (loss) income attributable to noncontrolling interests | (9) | | | 92 | | | 74 | |
| Net income attributable to common shareholders | $ | 2,010 |
|
| $ | 3,786 |
|
| $ | 1,121 |
| Net income attributable to common shareholders | $ | 1,963 | | | $ | 2,936 | | | $ | 2,005 | |
| Comprehensive income, net of income taxes | | | | | | Comprehensive income, net of income taxes | | | | | |
| Net income | $ | 2,084 |
| | $ | 3,876 |
| | $ | 1,196 |
| Net income | $ | 1,954 | | | $ | 3,028 | | | $ | 2,079 | |
| Other comprehensive income (loss), net of income taxes | | | | | | Other comprehensive income (loss), net of income taxes | |
| Pension and non-pension postretirement benefit plans: | | | | | | Pension and non-pension postretirement benefit plans: | |
| Prior service benefit reclassified to periodic benefit cost | (66 | ) | | (56 | ) | | (48 | ) | Prior service benefit reclassified to periodic benefit cost | (40) | | | (65) | | | (66) | |
| Actuarial loss reclassified to periodic benefit cost | 247 |
| | 197 |
| | 184 |
| Actuarial loss reclassified to periodic benefit cost | 190 | | | 149 | | | 247 | |
| | Pension and non-pension postretirement benefit plan valuation adjustment | (143 | ) | | 10 |
| | (181 | ) | Pension and non-pension postretirement benefit plan valuation adjustment | (357) | | | (289) | | | (143) | |
| Unrealized gain on cash flow hedges | 12 |
| | 3 |
| | 2 |
| |
| Unrealized gain on marketable securities | — |
| | 6 |
| | 1 |
| |
| Unrealized gain (loss) on investments in unconsolidated affiliates | 2 |
| | 4 |
| | (4 | ) | |
| Unrealized (loss) gain on foreign currency translation | (10 | ) | | 7 |
| | 10 |
| |
| Unrealized (loss) gain on cash flow hedges | | Unrealized (loss) gain on cash flow hedges | (3) | | | 0 | | | 12 | |
| | Unrealized gain on investments in unconsolidated affiliates | | Unrealized gain on investments in unconsolidated affiliates | 0 | | | 1 | | | 2 | |
| Unrealized gain (loss) on foreign currency translation | | Unrealized gain (loss) on foreign currency translation | 4 | | | 6 | | | (10) | |
| | Other comprehensive income (loss) | 42 |
|
| 171 |
|
| (36 | ) | Other comprehensive income (loss) | (206) | | | (198) | | | 42 | |
| Comprehensive income | 2,126 |
|
| 4,047 |
|
| 1,160 |
| Comprehensive income | 1,748 | | | 2,830 | | | 2,121 | |
| Comprehensive income attributable to noncontrolling interests and preference stock dividends | 75 |
| | 88 |
| | 75 |
| |
| Comprehensive (loss) income attributable to noncontrolling interests | | Comprehensive (loss) income attributable to noncontrolling interests | (9) | | | 93 | | | 75 | |
| Comprehensive income attributable to common shareholders | $ | 2,051 |
| | $ | 3,959 |
|
| $ | 1,085 |
| Comprehensive income attributable to common shareholders | $ | 1,757 | | | $ | 2,737 | | | $ | 2,046 | |
| | | | | | | | | | | | |
| Average shares of common stock outstanding: | | | | | | Average shares of common stock outstanding: | |
| Basic | 967 |
| | 947 |
| | 924 |
| Basic | 976 | | | 973 | | | 967 | |
| Diluted | 969 |
| | 949 |
| | 927 |
| |
| Assumed exercise and/or distributions of stock-based awards | | Assumed exercise and/or distributions of stock-based awards | 1 | | | 1 | | | 2 | |
Diluted(a) | | Diluted(a) | 977 | | | 974 | | | 969 | |
| Earnings per average common share: | | | | | | Earnings per average common share: | | | | | |
| Basic | $ | 2.08 |
| | $ | 4.00 |
| | $ | 1.21 |
| Basic | $ | 2.01 | | | $ | 3.02 | | | $ | 2.07 | |
| Diluted | $ | 2.07 |
|
| $ | 3.99 |
| | $ | 1.21 |
| Diluted | $ | 2.01 | | | $ | 3.01 | | | $ | 2.07 | |
__________
(a)The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was less than 1 million for the years ended December 31, 2020 and December 31, 2019 and approximately 3 million for the year ended December 31, 2018.
See the Combined Notes to Consolidated Financial Statements
212179
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 1,954 | | | $ | 3,028 | | | $ | 2,079 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | |
| Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | 6,527 | | | 5,780 | | | 5,971 | |
| Asset impairments | 591 | | | 201 | | | 50 | |
| Gain on sales of assets and businesses | (24) | | | (27) | | | (56) | |
| | | | | |
| | | | | |
| Deferred income taxes and amortization of investment tax credits | 309 | | | 681 | | | (108) | |
| Net fair value changes related to derivatives | (268) | | | 222 | | | 294 | |
| Net realized and unrealized (gains) losses on NDT funds | (461) | | | (663) | | | 303 | |
| Unrealized gain on equity investments | (186) | | | 0 | | | 0 | |
| Other non-cash operating activities | 592 | | | 613 | | | 1,131 | |
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | 697 | | | (243) | | | (565) | |
| Inventories | (85) | | | (87) | | | (37) | |
| Accounts payable and accrued expenses | (129) | | | (425) | | | 551 | |
| Option premiums (paid), net | (139) | | | (29) | | | (43) | |
| Collateral received (posted), net | 494 | | | (438) | | | 82 | |
| Income taxes | 140 | | | (64) | | | 340 | |
| Pension and non-pension postretirement benefit contributions | (601) | | | (408) | | | (383) | |
| | | | | |
| Other assets and liabilities | (5,176) | | | (1,482) | | | (965) | |
| Net cash flows provided by operating activities | 4,235 | | | 6,659 | | | 8,644 | |
| Cash flows from investing activities | | | | | |
| Capital expenditures | (8,048) | | | (7,248) | | | (7,594) | |
| | | | | |
| Proceeds from NDT fund sales | 3,341 | | | 10,051 | | | 8,762 | |
| Investment in NDT funds | (3,464) | | | (10,087) | | | (8,997) | |
| Collection of DPP | 3,771 | | | 0 | | | 0 | |
| Acquisitions of assets and businesses, net | 0 | | | (41) | | | (154) | |
| Proceeds from sales of assets and businesses | 46 | | | 53 | | | 91 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Other investing activities | 18 | | | 12 | | | 58 | |
| Net cash flows used in investing activities | (4,336) | | | (7,260) | | | (7,834) | |
| Cash flows from financing activities | | | | | |
| | | | | |
| Changes in short-term borrowings | 161 | | | 781 | | | (338) | |
| Proceeds from short-term borrowings with maturities greater than 90 days | 500 | | | 0 | | | 126 | |
| Repayments on short-term borrowings with maturities greater than 90 days | 0 | | | (125) | | | (1) | |
| Issuance of long-term debt | 7,507 | | | 1,951 | | | 3,115 | |
| Retirement of long-term debt | (6,440) | | | (1,287) | | | (1,786) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Dividends paid on common stock | (1,492) | | | (1,408) | | | (1,332) | |
| | | | | |
| Proceeds from employee stock plans | 45 | | | 112 | | | 105 | |
| | | | | |
| Other financing activities | (136) | | | (82) | | | (108) | |
| Net cash flows provided by (used in) financing activities | 145 | | | (58) | | | (219) | |
| Increase (decrease) in cash, restricted cash, and cash equivalents | 44 | | | (659) | | | 591 | |
| Cash, restricted cash, and cash equivalents at beginning of period | 1,122 | | | 1,781 | | | 1,190 | |
| Cash, restricted cash, and cash equivalents at end of period | $ | 1,166 | | | $ | 1,122 | | | $ | 1,781 | |
| | | | | |
| Supplemental cash flow information | | | | | |
| Increase (decrease) in capital expenditures not paid | $ | 194 | | | $ | (7) | | | $ | (69) | |
| Increase in DPP | 4,441 | | | 0 | | | 0 | |
| Increase (decrease) in PP&E related to ARO update | 850 | | | 968 | | | (107) | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 2,084 |
| | $ | 3,876 |
| | $ | 1,196 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | |
| Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization | 5,971 |
| | 5,427 |
| | 5,576 |
|
| Impairment losses of long-lived assets, intangibles and regulatory assets | 50 |
| | 573 |
| | 306 |
|
Gain on deconsolidation of business
| — |
| | (213 | ) | | — |
|
| (Gain) loss on sales of assets and businesses | (56 | ) | | (3 | ) | | 48 |
|
| Bargain purchase gain | — |
| | (233 | ) | | — |
|
| Deferred income taxes and amortization of investment tax credits | (106 | ) | | (362 | ) | | 656 |
|
| Net fair value changes related to derivatives | 294 |
| | 151 |
| | 24 |
|
| Net realized and unrealized losses (gains) on NDT funds | 303 |
| | (616 | ) | | (229 | ) |
| Other non-cash operating activities | 1,124 |
| | 721 |
| | 1,333 |
|
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | (565 | ) | | (470 | ) | | (432 | ) |
| Inventories | (37 | ) | | (72 | ) | | 7 |
|
| Accounts payable and accrued expenses | 551 |
| | (388 | ) | | 771 |
|
| Option premiums (paid) received, net | (43 | ) | | 28 |
| | (66 | ) |
| Collateral received (posted), net | 82 |
| | (158 | ) | | 931 |
|
| Income taxes | 340 |
| | 299 |
| | 576 |
|
| Pension and non-pension postretirement benefit contributions | (383 | ) | | (405 | ) | | (397 | ) |
| Deposit with IRS | — |
| | — |
| | (1,250 | ) |
| Other assets and liabilities | (965 | ) | | (675 | ) | | (589 | ) |
| Net cash flows provided by operating activities | 8,644 |
|
| 7,480 |
|
| 8,461 |
|
| Cash flows from investing activities | | | | | |
| Capital expenditures | (7,594 | ) | | (7,584 | ) | | (8,553 | ) |
| Proceeds from termination of direct financing lease investment | — |
| | — |
| | 360 |
|
| Proceeds from NDT fund sales | 8,762 |
| | 7,845 |
| | 9,496 |
|
| Investment in NDT funds | (8,997 | ) | | (8,113 | ) | | (9,738 | ) |
| Reduction of restricted cash from deconsolidation of business | — |
| | (87 | ) | | — |
|
| Acquisitions of assets and businesses, net | (154 | ) | | (208 | ) | | (6,923 | ) |
| Proceeds from sales of assets and businesses | 91 |
| | 219 |
| | 61 |
|
| Other investing activities | 58 |
| | (43 | ) | | (153 | ) |
| Net cash flows used in investing activities | (7,834 | ) |
| (7,971 | ) |
| (15,450 | ) |
| Cash flows from financing activities | | | | | |
| Changes in short-term borrowings | (338 | ) | | (261 | ) | | (353 | ) |
| Proceeds from short-term borrowings with maturities greater than 90 days | 126 |
| | 621 |
| | 240 |
|
| Repayments on short-term borrowings with maturities greater than 90 days | (1 | ) | | (700 | ) | | (462 | ) |
| Issuance of long-term debt | 3,115 |
| | 3,470 |
| | 4,716 |
|
| Retirement of long-term debt | (1,786 | ) | | (2,490 | ) | | (1,936 | ) |
| Retirement of long-term debt to financing trust | — |
| | (250 | ) | | — |
|
Common stock issued from treasury stock
| — |
| | 1,150 |
| | — |
|
| Redemption of preference stock | — |
| | — |
| | (190 | ) |
| Dividends paid on common stock | (1,332 | ) | | (1,236 | ) | | (1,166 | ) |
| Proceeds from employee stock plans | 105 |
| | 150 |
| | 55 |
|
| Sale of noncontrolling interests | — |
| | 396 |
| | 372 |
|
| Other financing activities | (108 | ) | | (83 | ) | | (85 | ) |
| Net cash flows (used in) provided by financing activities | (219 | ) |
| 767 |
|
| 1,191 |
|
| Increase (decrease) in cash, cash equivalents and restricted cash | 591 |
| | 276 |
| | (5,798 | ) |
| Cash, cash equivalents and restricted cash at beginning of period | 1,190 |
| | 914 |
| | 6,712 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 1,781 |
|
| $ | 1,190 |
|
| $ | 914 |
|
See the Combined Notes to Consolidated Financial Statements
213180
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
| | | | | | | | | | | |
| December 31, |
| (In millions) | 2020 | | 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 663 | | | $ | 587 | |
| Restricted cash and cash equivalents | 438 | | | 358 | |
| | | |
| Accounts receivable | | | |
| Customer accounts receivable | 3,597 | | 4,835 |
| Customer allowance for credit losses | (366) | | (243) |
| Customer accounts receivable, net | 3,231 | | | 4,592 | |
| Other accounts receivable | 1,469 | | 1,631 |
| Other allowance for credit losses | (71) | | (48) |
| Other accounts receivable, net | 1,398 | | | 1,583 | |
| Mark-to-market derivative assets | 644 | | | 679 | |
| Unamortized energy contract assets | 38 | | | 47 | |
| Inventories, net | | | |
| Fossil fuel and emission allowances | 297 | | | 312 | |
| Materials and supplies | 1,425 | | | 1,456 | |
| | | |
| Regulatory assets | 1,228 | | | 1,170 | |
| Renewable energy credits | 633 | | | 348 | |
| Assets held for sale | 958 | | | 0 | |
| Other | 1,609 | | | 905 | |
| Total current assets | 12,562 | | | 12,037 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $26,727 and $23,979 as of December 31, 2020 and 2019, respectively) | 82,584 | | | 80,233 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 8,759 | | | 8,335 | |
| Nuclear decommissioning trust funds | 14,464 | | | 13,190 | |
| Investments | 440 | | | 464 | |
| | | |
| Goodwill | 6,677 | | | 6,677 | |
| Mark-to-market derivative assets | 555 | | | 508 | |
| Unamortized energy contract assets | 294 | | | 336 | |
| | | |
| Other | 2,982 | | | 3,197 | |
| Total deferred debits and other assets | 34,171 | | | 32,707 | |
Total assets(a) | $ | 129,317 | | | $ | 124,977 | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 1,349 |
| | $ | 898 |
|
| Restricted cash and cash equivalents | 247 |
| | 207 |
|
| Accounts receivable, net | | | |
| Customer | 4,607 |
| | 4,445 |
|
| Other | 1,256 |
| | 1,132 |
|
| Mark-to-market derivative assets | 804 |
| | 976 |
|
| Unamortized energy contract assets | 48 |
| | 60 |
|
| Inventories, net | | | |
| Fossil fuel and emission allowances | 334 |
| | 340 |
|
| Materials and supplies | 1,351 |
| | 1,311 |
|
| Regulatory assets | 1,222 |
| | 1,267 |
|
| Assets held for sale | 904 |
|
| — |
|
| Other | 1,238 |
| | 1,260 |
|
| Total current assets | 13,360 |
|
| 11,896 |
|
| Property, plant and equipment, net | 76,707 |
| | 74,202 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 8,237 |
| | 8,021 |
|
| Nuclear decommissioning trust funds | 11,661 |
| | 13,272 |
|
| Investments | 625 |
| | 640 |
|
| Goodwill | 6,677 |
| | 6,677 |
|
| Mark-to-market derivative assets | 452 |
| | 337 |
|
| Unamortized energy contract assets | 372 |
| | 395 |
|
| Other | 1,575 |
| | 1,330 |
|
| Total deferred debits and other assets | 29,599 |
|
| 30,672 |
|
Total assets(a) | $ | 119,666 |
|
| $ | 116,770 |
|
See the Combined Notes to Consolidated Financial Statements
214181
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
| | | | December 31, | | December 31, |
| (In millions) | 2018 | | 2017 | (In millions) | 2020 | | 2019 |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities | | | | Current liabilities | |
| Short-term borrowings | $ | 714 |
| | $ | 929 |
| Short-term borrowings | $ | 2,031 | | | $ | 1,370 | |
| Long-term debt due within one year | 1,349 |
| | 2,088 |
| Long-term debt due within one year | 1,819 | | | 4,710 | |
| Accounts payable | 3,800 |
| | 3,532 |
| Accounts payable | 3,562 | | | 3,560 | |
| Accrued expenses | 2,112 |
| | 1,837 |
| Accrued expenses | 2,078 | | | 1,981 | |
| Payables to affiliates | 5 |
| | 5 |
| Payables to affiliates | 5 | | | 5 | |
| | Regulatory liabilities | 644 |
| | 523 |
| Regulatory liabilities | 581 | | | 406 | |
| Mark-to-market derivative liabilities | 475 |
| | 232 |
| Mark-to-market derivative liabilities | 295 | | | 247 | |
| Unamortized energy contract liabilities | 149 |
| | 231 |
| Unamortized energy contract liabilities | 100 | | | 132 | |
| Renewable energy credit obligation | 344 |
| | 352 |
| Renewable energy credit obligation | 661 | | | 443 | |
| | Liabilities held for sale | 777 |
| | — |
| Liabilities held for sale | 375 | | | 0 | |
| Other | 1,035 |
| | 1,069 |
| Other | 1,264 | | | 1,331 | |
| Total current liabilities | 11,404 |
|
| 10,798 |
| Total current liabilities | 12,771 | | | 14,185 | |
| Long-term debt | 34,075 |
| | 32,176 |
| Long-term debt | 35,093 | | | 31,329 | |
| Long-term debt to financing trusts | 390 |
| | 389 |
| Long-term debt to financing trusts | 390 | | | 390 | |
| Deferred credits and other liabilities | | | | Deferred credits and other liabilities | |
| Deferred income taxes and unamortized investment tax credits | 11,330 |
| | 11,235 |
| Deferred income taxes and unamortized investment tax credits | 13,035 | | | 12,351 | |
| Asset retirement obligations | 9,679 |
| | 10,029 |
| Asset retirement obligations | 12,300 | | | 10,846 | |
| Pension obligations | 3,988 |
| | 3,736 |
| Pension obligations | 4,503 | | | 4,247 | |
| Non-pension postretirement benefit obligations | 1,928 |
| | 2,093 |
| Non-pension postretirement benefit obligations | 2,011 | | | 2,076 | |
| Spent nuclear fuel obligation | 1,171 |
| | 1,147 |
| Spent nuclear fuel obligation | 1,208 | | | 1,199 | |
| Regulatory liabilities | 9,559 |
| | 9,865 |
| Regulatory liabilities | 9,485 | | | 9,986 | |
| Mark-to-market derivative liabilities | 479 |
| | 409 |
| Mark-to-market derivative liabilities | 473 | | | 393 | |
| Unamortized energy contract liabilities | 463 |
| | 609 |
| Unamortized energy contract liabilities | 238 | | | 338 | |
| | Other | 2,130 |
| | 2,097 |
| Other | 2,942 | | | 3,064 | |
| Total deferred credits and other liabilities | 40,727 |
|
| 41,220 |
| Total deferred credits and other liabilities | 46,195 | | | 44,500 | |
Total liabilities(a) | 86,596 |
|
| 84,583 |
| Total liabilities(a) | 94,449 | | | 90,404 | |
| Commitments and contingencies |
| |
| Commitments and contingencies | 0 | | 0 |
| | Shareholders’ equity | | | | Shareholders’ equity | |
| Common stock (No par value, 2,000 shares authorized, 968 shares and 963 shares outstanding at December 31, 2018 and 2017, respectively) | 19,116 |
| | 18,964 |
| |
| Treasury stock, at cost (2 shares at December 31, 2018 and 2017) | (123 | ) | | (123 | ) | |
| Common stock (No par value, 2,000 shares authorized, 976 shares and 973 shares outstanding at December 31, 2020 and 2019, respectively) | | Common stock (No par value, 2,000 shares authorized, 976 shares and 973 shares outstanding at December 31, 2020 and 2019, respectively) | 19,373 | | | 19,274 | |
| Treasury stock, at cost (2 shares at December 31, 2020 and 2019) | | Treasury stock, at cost (2 shares at December 31, 2020 and 2019) | (123) | | | (123) | |
| Retained earnings | 14,766 |
| | 14,081 |
| Retained earnings | 16,735 | | | 16,267 | |
| Accumulated other comprehensive loss, net | (2,995 | ) | | (3,026 | ) | Accumulated other comprehensive loss, net | (3,400) | | | (3,194) | |
| Total shareholders’ equity | 30,764 |
|
| 29,896 |
| Total shareholders’ equity | 32,585 | | | 32,224 | |
| | Noncontrolling interests | 2,306 |
| | 2,291 |
| Noncontrolling interests | 2,283 | | | 2,349 | |
| Total equity | 33,070 |
|
| 32,187 |
| Total equity | 34,868 | | | 34,573 | |
| Total liabilities and equity | $ | 119,666 |
|
| $ | 116,770 |
| |
| Total liabilities and shareholders' equity | | Total liabilities and shareholders' equity | $ | 129,317 | | | $ | 124,977 | |
__________
| |
(a) | Exelon’s consolidated assets include $9,667 million and $9,597 million at December 31, 2018 and 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,548 million and $3,618 million at December 31, 2018 and 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities for additional information. |
(a)Exelon’s consolidated assets include $10,200 million and $9,532 million at December 31, 2020 and 2019, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,598 million and $3,473 million at December 31, 2020 and 2019, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 23–Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
215182
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Changes in Equity
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Shareholders' Equity | | | | |
| (In millions, shares in thousands) | Issued
Shares | | Common
Stock | | Treasury
Stock | | Retained
Earnings | | Accumulated
Other
Comprehensive
Loss | | Noncontrolling
Interests | | Total
Equity |
| Balance, December 31, 2017 | 965,168 | | | $ | 18,964 | | | $ | (123) | | | $ | 14,063 | | | $ | (3,026) | | | $ | 2,291 | | | $ | 32,169 | |
| Net income | — | | | — | | | — | | | 2,005 | | | — | | | 74 | | | 2,079 | |
| Long-term incentive plan activity | 3,534 | | | 41 | | | 0 | | | 0 | | | 0 | | | 0 | | | 41 | |
| Employee stock purchase plan issuances | 1,318 | | | 105 | | | 0 | | | 0 | | | 0 | | | 0 | | | 105 | |
| Sale of noncontrolling interests | — | | | 6 | | | — | | | — | | | — | | | 0 | | | 6 | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (60) | | | (60) | |
| | | | | | | | | | | | | |
Common stock dividends ($1.38/common share) | — | | | — | | | — | | | (1,339) | | | — | | | — | | | (1,339) | |
| Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 41 | | | 1 | | | 42 | |
| Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard | — | | | — | | | — | | | 14 | | | (10) | | | — | | | 4 | |
| Balance, December 31, 2018 | 970,020 | | | $ | 19,116 | | | $ | (123) | | | $ | 14,743 | | | $ | (2,995) | | | $ | 2,306 | | | $ | 33,047 | |
| Net income | — | | | — | | | — | | | 2,936 | | | — | | | 92 | | | 3,028 | |
Long-term incentive plan
activity | 3,111 | | | 40 | | | 0 | | | 0 | | | 0 | | | 0 | | | 40 | |
Employee stock purchase
plan issuances | 1,285 | | | 112 | | | 0 | | | 0 | | | 0 | | | 0 | | | 112 | |
| Sale of noncontrolling interests | — | | | 6 | | | — | | | — | | | — | | | 0 | | | 6 | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (48) | | | (48) | |
Common stock dividends ($1.45/common share) | — | | | — | | | — | | | (1,412) | | | — | | | — | | | (1,412) | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | (199) | | | (1) | | | (200) | |
| Balance, December 31, 2019 | 974,416 | | | $ | 19,274 | | | $ | (123) | | | $ | 16,267 | | | $ | (3,194) | | | $ | 2,349 | | | $ | 34,573 | |
| Net income (loss) | — | | | — | | | — | | | 1,963 | | | — | | | (9) | | | 1,954 | |
| Long-term incentive plan activity | 1,570 | | | 40 | | | 0 | | | 0 | | | 0 | | | 0 | | | 40 | |
| Employee stock purchase plan issuances | 1,480 | | | 56 | | | 0 | | | 0 | | | 0 | | | 0 | | | 56 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Sale of noncontrolling interests | — | | | 3 | | | — | | | — | | | — | | | 0 | | | 3 | |
| Changes in equity of noncontrolling interests | — | | | 0 | | | — | | | — | | | — | | | (57) | | | (57) | |
| | | | | | | | | | | | | |
Common stock dividends ($1.53/common share)
| — | | | — | | | — | | | (1,495) | | | — | | | — | | | (1,495) | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | (206) | | | 0 | | | (206) | |
| Balance, December 31, 2020 | 977,466 | | | $ | 19,373 | | | $ | (123) | | | $ | 16,735 | | | $ | (3,400) | | | $ | 2,283 | | | $ | 34,868 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Shareholders' Equity | | | | | | |
| (In millions, shares in thousands) | Issued
Shares | | Common
Stock | | Treasury
Stock | | Retained
Earnings | | Accumulated
Other
Comprehensive
Loss | | Noncontrolling
Interests | | Preference
Stock | | Total
Equity |
| Balance, December 31, 2015 | 954,668 |
| | $ | 18,676 |
| | $ | (2,327 | ) | | $ | 12,104 |
| | $ | (2,624 | ) | | $ | 1,308 |
| | $ | 193 |
| | $ | 27,330 |
|
| Net income | — |
| | — |
| | — |
| | 1,121 |
| | — |
| | 67 |
| | 8 |
| | 1,196 |
|
| Long-term incentive plan activity | 2,868 |
| | 85 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 85 |
|
| Employee stock purchase plan issuances | 1,242 |
| | 55 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 55 |
|
| Tax benefit on stock compensation | — |
| | (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (18 | ) |
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | 5 |
| | — |
| | 5 |
|
| Adjustment of contingently redeemable noncontrolling interest to redemption value | — |
| | — |
| | — |
| | — |
| | — |
| | 157 |
| | — |
| | 157 |
|
Common stock dividends ($1.26/common share) | — |
| | — |
| | — |
| | (1,172 | ) | | — |
| | — |
| | — |
| | (1,172 | ) |
| Preferred and preference stock | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (8 | ) | | (8 | ) |
| Sale of noncontrolling interests | — |
| | (4 | ) | | — |
| | — |
| | — |
| | 243 |
| | — |
| | 239 |
|
| Redemption of preference stock | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (193 | ) | | (193 | ) |
| Other comprehensive loss, net of income taxes | — |
| | — |
| | — |
| | — |
| | (36 | ) | | — |
| | — |
| | (36 | ) |
| Balance, December 31, 2016 | 958,778 |
|
| $ | 18,794 |
|
| $ | (2,327 | ) |
| $ | 12,053 |
|
| $ | (2,660 | ) |
| $ | 1,780 |
|
| $ | — |
|
| $ | 27,640 |
|
| Net income | — |
| | — |
| | — |
| | 3,786 |
| | — |
| | 90 |
| | — |
| | 3,876 |
|
Long-term incentive plan
activity | 5,066 |
| | 56 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 56 |
|
Employee stock purchase
plan issuances | 1,324 |
| | 150 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 150 |
|
| Common stock issued from treasury stock | — |
| | — |
| | 2,204 |
| | (1,054 | ) | | — |
| | — |
| | — |
| | 1,150 |
|
| Sale of noncontrolling interests | — |
| | (36 | ) | | — |
| | — |
| | — |
| | 443 |
| | — |
| | 407 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (20 | ) | | — |
| | (20 | ) |
Common stock dividends ($1.31/common share) | — |
| | — |
| | — |
| | (1,243 | ) | | — |
| | — |
| | — |
| | (1,243 | ) |
| Other comprehensive income (loss), net of income taxes | — |
| | — |
| | — |
| | — |
| | 173 |
| | (2 | ) | | — |
| | 171 |
|
| Impact of adoption of Reclassification of Certain Tax Effects from AOCI standard | — |
| | — |
| | — |
| | 539 |
| | (539 | ) | | — |
| | — |
| | — |
|
| Balance, December 31, 2017 | 965,168 |
|
| $ | 18,964 |
|
| $ | (123 | ) |
| $ | 14,081 |
|
| $ | (3,026 | ) |
| $ | 2,291 |
|
| $ | — |
|
| $ | 32,187 |
|
| Net income | — |
| | — |
| | — |
| | 2,010 |
| | — |
| | 74 |
| | — |
| | 2,084 |
|
| Long-term incentive plan activity | 3,534 |
| | 41 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 41 |
|
| Employee stock purchase plan issuances | 1,318 |
| | 105 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 105 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (60 | ) | | — |
| | (60 | ) |
| Sale of noncontrolling interests | — |
| | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 6 |
|
Common stock dividends ($1.38/common share)
| — |
| | — |
| | — |
| | (1,339 | ) | | — |
| | — |
| | — |
| | (1,339 | ) |
| Other comprehensive income, net of income taxes | — |
| | — |
| | — |
| | — |
| | 41 |
| | 1 |
| | — |
| | 42 |
|
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard
| — |
| | — |
| | — |
| | 14 |
| | (10 | ) | | — |
| | — |
| | 4 |
|
| Balance, December 31, 2018 | 970,020 |
|
| $ | 19,116 |
|
| $ | (123 | ) |
| $ | 14,766 |
|
| $ | (2,995 | ) |
| $ | 2,306 |
|
| $ | — |
|
| $ | 33,070 |
|
See the Combined Notes to Consolidated Financial Statements
216183
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Operating revenues | | | | | |
| Operating revenues | $ | 16,392 | | | $ | 17,752 | | | $ | 19,169 | |
| Operating revenues from affiliates | 1,211 | | | 1,172 | | | 1,268 | |
| Total operating revenues | 17,603 | | | 18,924 | | | 20,437 | |
| Operating expenses | | | | | |
| Purchased power and fuel | 9,592 | | | 10,849 | | | 11,679 | |
| Purchased power and fuel from affiliates | (7) | | | 7 | | | 14 | |
| Operating and maintenance | 4,613 | | | 4,131 | | | 4,803 | |
| Operating and maintenance from affiliates | 555 | | | 587 | | | 661 | |
| Depreciation and amortization | 2,123 | | | 1,535 | | | 1,797 | |
| Taxes other than income taxes | 482 | | | 519 | | | 556 | |
| Total operating expenses | 17,358 | | | 17,628 | | | 19,510 | |
| | | | | |
| Gain on sales of assets and businesses | 11 | | | 27 | | | 48 | |
| | | | | |
| | | | | |
| Operating income | 256 | | | 1,323 | | | 975 | |
| Other income and (deductions) | | | | | |
| Interest expense, net | (328) | | | (394) | | | (396) | |
| Interest expense to affiliates | (29) | | | (35) | | | (36) | |
| Other, net | 937 | | | 1,023 | | | (178) | |
| Total other income and (deductions) | 580 | | | 594 | | | (610) | |
| Income before income taxes | 836 | | | 1,917 | | | 365 | |
| Income taxes | 249 | | | 516 | | | (108) | |
| Equity in losses of unconsolidated affiliates | (8) | | | (184) | | | (30) | |
| Net income | 579 | | | 1,217 | | | 443 | |
| Net (loss) income attributable to noncontrolling interests | (10) | | | 92 | | | 73 | |
| Net income attributable to membership interest | $ | 589 | | | $ | 1,125 | | | $ | 370 | |
| Comprehensive income, net of income taxes | | | | | |
| Net income | $ | 579 | | | $ | 1,217 | | | $ | 443 | |
| Other comprehensive income (loss), net of income taxes | | | | | |
| Unrealized (loss) gain on cash flow hedges | (2) | | | 0 | | | 12 | |
| | | | | |
| Unrealized gain on investments in unconsolidated affiliates | 0 | | | 1 | | | 1 | |
| Unrealized gain (loss) on foreign currency translation | 4 | | | 6 | | | (10) | |
| | | | | |
| Other comprehensive income | 2 | | | 7 | | | 3 | |
| Comprehensive income | $ | 581 | | | $ | 1,224 | | | $ | 446 | |
| Comprehensive (loss) income attributable to noncontrolling interests | (10) | | | 93 | | | 74 | |
| Comprehensive income attributable to membership interest | $ | 591 | | | $ | 1,131 | | | $ | 372 | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Operating revenues | | | | | |
| Operating revenues | $ | 19,169 |
| | $ | 17,385 |
| | $ | 16,318 |
|
| Operating revenues from affiliates | 1,268 |
| | 1,115 |
| | 1,439 |
|
| Total operating revenues | 20,437 |
|
| 18,500 |
|
| 17,757 |
|
| Operating expenses | | | | | |
| Purchased power and fuel | 11,679 |
| | 9,671 |
| | 8,818 |
|
| Purchased power and fuel from affiliates | 14 |
| | 19 |
| | 12 |
|
| Operating and maintenance | 4,803 |
| | 5,602 |
| | 5,000 |
|
| Operating and maintenance from affiliates | 661 |
| | 697 |
| | 663 |
|
| Depreciation and amortization | 1,797 |
| | 1,457 |
| | 1,879 |
|
| Taxes other than income | 556 |
| | 555 |
| | 506 |
|
| Total operating expenses | 19,510 |
|
| 18,001 |
|
| 16,878 |
|
| Gain (loss) on sales of assets and businesses | 48 |
| | 2 |
| | (59 | ) |
| Bargain purchase gain | — |
| | 233 |
| | — |
|
| Gain on deconsolidation of business | — |
| | 213 |
| | — |
|
| Operating income | 975 |
| | 947 |
| | 820 |
|
| Other income and (deductions) | | | | | |
| Interest expense, net | (396 | ) | | (401 | ) | | (325 | ) |
| Interest expense to affiliates | (36 | ) | | (39 | ) | | (39 | ) |
| Other, net | (178 | ) | | 948 |
| | 401 |
|
| Total other income and (deductions) | (610 | ) |
| 508 |
|
| 37 |
|
| Income before income taxes | 365 |
| | 1,455 |
| | 857 |
|
| Income taxes | (108 | ) | | (1,376 | ) | | 282 |
|
| Equity in losses of unconsolidated affiliates | (30 | ) | | (33 | ) | | (25 | ) |
| Net income | 443 |
|
| 2,798 |
|
| 550 |
|
| Net income attributable to noncontrolling interests | 73 |
| | 88 |
| | 67 |
|
| Net income attributable to membership interest | $ | 370 |
|
| $ | 2,710 |
|
| $ | 483 |
|
| Comprehensive income, net of income taxes | | | | | |
| Net income | $ | 443 |
| | $ | 2,798 |
| | $ | 550 |
|
| Other comprehensive income (loss), net of income taxes | | | | | |
| Unrealized gain on cash flow hedges | 12 |
| | 3 |
| | 2 |
|
| Unrealized gain (loss) on investments in unconsolidated affiliates | 1 |
| | 4 |
| | (4 | ) |
| Unrealized (loss) gain on foreign currency translation | (10 | ) | | 7 |
| | 10 |
|
| Unrealized gain on marketable securities | — |
| | 1 |
| | 1 |
|
| Other comprehensive income | 3 |
|
| 15 |
|
| 9 |
|
| Comprehensive income | $ | 446 |
|
| $ | 2,813 |
|
| $ | 559 |
|
| Comprehensive income attributable to noncontrolling interests | 74 |
| | 86 |
| | 67 |
|
| Comprehensive income attributable to membership interest | $ | 372 |
| | $ | 2,727 |
| | $ | 492 |
|
See the Combined Notes to Consolidated Financial Statements
217184
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Cash Flows | | | | For the Years Ended December 31, | | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 | (In millions) | 2020 | | 2019 | | 2018 |
| Cash flows from operating activities | | | | | | Cash flows from operating activities | | | | | |
| Net income | $ | 443 |
| | $ | 2,798 |
| | $ | 550 |
| Net income | $ | 579 | | | $ | 1,217 | | | $ | 443 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | Adjustments to reconcile net income to net cash flows provided by operating activities: | |
| Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization | 3,415 |
| | 3,056 |
| | 3,519 |
| |
| Impairment losses of long-lived assets | 50 |
| | 510 |
| | 243 |
| |
| Gain on deconsolidation of business | — |
| | (213 | ) | | — |
| |
| (Gain) loss on sales of assets and businesses | (48 | ) | | (2 | ) | | 59 |
| |
| Bargain purchase gain | — |
| | (233 | ) | | — |
| |
| Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | | Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | 3,636 | | | 3,063 | | | 3,415 | |
| Asset impairments | | Asset impairments | 563 | | | 201 | | | 50 | |
| Gain on sales of assets and businesses | | Gain on sales of assets and businesses | (11) | | | (27) | | | (48) | |
| | Deferred income taxes and amortization of investment tax credits | (451 | ) | | (2,023 | ) | | (277 | ) | Deferred income taxes and amortization of investment tax credits | 78 | | | 361 | | | (451) | |
| Net fair value changes related to derivatives | 307 |
| | 167 |
| | 40 |
| Net fair value changes related to derivatives | (270) | | | 228 | | | 307 | |
| Net realized and unrealized losses (gains) on NDT fund investments | 303 |
| | (616 | ) | | (229 | ) | |
| Net realized and unrealized (gains) losses on NDT fund investments | | Net realized and unrealized (gains) losses on NDT fund investments | (461) | | | (663) | | | 303 | |
| Unrealized gain on equity investments | | Unrealized gain on equity investments | (186) | | | 0 | | | 0 | |
| Other non-cash operating activities | 298 |
| | 112 |
| | 15 |
| Other non-cash operating activities | 18 | | | (124) | | | 298 | |
| Changes in assets and liabilities: | | | | | | Changes in assets and liabilities: | |
| Accounts receivable | (359 | ) | | (320 | ) | | (152 | ) | Accounts receivable | 1,125 | | | (186) | | | (359) | |
| Receivables from and payables to affiliates, net | 8 |
| | (7 | ) | | (21 | ) | Receivables from and payables to affiliates, net | 24 | | | (52) | | | 8 | |
| Inventories | (12 | ) | | (29 | ) | | (4 | ) | Inventories | (77) | | | (47) | | | (12) | |
| Accounts payable and accrued expenses | 376 |
| | 4 |
| | 29 |
| Accounts payable and accrued expenses | (343) | | | (248) | | | 376 | |
| Option premiums (paid) received, net | (43 | ) | | 28 |
| | (66 | ) | |
| Option premiums paid, net | | Option premiums paid, net | (139) | | | (29) | | | (43) | |
| Collateral received (posted), net | 64 |
| | (129 | ) | | 923 |
| Collateral received (posted), net | 479 | | | (481) | | | 64 | |
| Income taxes | (193 | ) | | 496 |
| | 182 |
| Income taxes | 186 | | | 302 | | | (193) | |
| Pension and non-pension postretirement benefit contributions | (139 | ) | | (148 | ) | | (152 | ) | Pension and non-pension postretirement benefit contributions | (255) | | | (175) | | | (139) | |
| Other assets and liabilities | (158 | ) | | (152 | ) | | (217 | ) | Other assets and liabilities | (4,362) | | | (467) | | | (158) | |
| Net cash flows provided by operating activities | 3,861 |
|
| 3,299 |
|
| 4,442 |
| Net cash flows provided by operating activities | 584 | | | 2,873 | | | 3,861 | |
| Cash flows from investing activities | | | | | | Cash flows from investing activities | | | | | |
| Capital expenditures | (2,242 | ) | | (2,259 | ) | | (3,078 | ) | Capital expenditures | (1,747) | | | (1,845) | | | (2,242) | |
| Proceeds from NDT fund sales | 8,762 |
| | 7,845 |
| | 9,496 |
| Proceeds from NDT fund sales | 3,341 | | | 10,051 | | | 8,762 | |
| Investment in NDT funds | (8,997 | ) | | (8,113 | ) | | (9,738 | ) | Investment in NDT funds | (3,464) | | | (10,087) | | | (8,997) | |
Reduction of restricted cash from deconsolidation of business
| — |
| | (87 | ) | | — |
| |
| | Collection of DPP | | Collection of DPP | 3,771 | | | 0 | | | 0 | |
| Proceeds from sales of assets and businesses | 90 |
| | 218 |
| | 37 |
| Proceeds from sales of assets and businesses | 46 | | | 52 | | | 90 | |
| Acquisitions of assets and businesses, net | (154 | ) | | (208 | ) | | (293 | ) | Acquisitions of assets and businesses, net | 0 | | | (41) | | | (154) | |
| | Other investing activities | 10 |
| | (58 | ) | | (240 | ) | Other investing activities | 11 | | | 3 | | | 10 | |
| Net cash flows used in investing activities | (2,531 | ) |
| (2,662 | ) |
| (3,816 | ) | |
| Net cash flows provided by (used in) investing activities | | Net cash flows provided by (used in) investing activities | 1,958 | | | (1,867) | | | (2,531) | |
| Cash flows from financing activities | | | | | | Cash flows from financing activities | | | | | |
| Change in short-term borrowings | — |
| | (620 | ) | | 620 |
| Change in short-term borrowings | 20 | | | 320 | | | 0 | |
| Proceeds from short-term borrowings with maturities greater than 90 days | 1 |
| | 121 |
| | 240 |
| Proceeds from short-term borrowings with maturities greater than 90 days | 500 | | | 0 | | | 0 | |
| Repayments of short-term borrowings with maturities greater than 90 days | (1 | ) | | (200 | ) | | (162 | ) | |
| | Issuance of long-term debt | 15 |
| | 1,645 |
| | 388 |
| Issuance of long-term debt | 3,155 | | | 42 | | | 15 | |
| Retirement of long-term debt | (141 | ) | | (1,261 | ) | | (202 | ) | Retirement of long-term debt | (4,334) | | | (813) | | | (141) | |
| | Retirement of long-term debt to affiliate | | Retirement of long-term debt to affiliate | (550) | | | 0 | | | 0 | |
| Changes in Exelon intercompany money pool | 46 |
| | (1 | ) | | (1,191 | ) | Changes in Exelon intercompany money pool | 285 | | | (100) | | | 46 | |
| Distributions to member | (1,001 | ) | | (659 | ) | | (922 | ) | Distributions to member | (1,734) | | | (899) | | | (1,001) | |
| | Contributions from member | 155 |
| | 102 |
| | 142 |
| Contributions from member | 64 | | | 41 | | | 155 | |
| Sale of noncontrolling interests | — |
| | 396 |
| | 372 |
| |
| | Other financing activities | (55 | ) | | (54 | ) | | (19 | ) | Other financing activities | (70) | | | (51) | | | (55) | |
| Net cash flows used in financing activities | (981 | ) |
| (531 | ) |
| (734 | ) | Net cash flows used in financing activities | (2,664) | | | (1,460) | | | (981) | |
| Increase (decrease) in cash, cash equivalents and restricted cash | 349 |
| | 106 |
| | (108 | ) | |
| Cash, cash equivalents and restricted cash at beginning of period | 554 |
| | 448 |
| | 556 |
| |
| Cash, cash equivalents and restricted cash at end of period | $ | 903 |
|
| $ | 554 |
|
| $ | 448 |
| |
| (Decrease) increase in cash, restricted cash, and cash equivalents | | (Decrease) increase in cash, restricted cash, and cash equivalents | (122) | | | (454) | | | 349 | |
| Cash, restricted cash, and cash equivalents at beginning of period | | Cash, restricted cash, and cash equivalents at beginning of period | 449 | | | 903 | | | 554 | |
| Cash, restricted cash, and cash equivalents at end of period | | Cash, restricted cash, and cash equivalents at end of period | $ | 327 | | | $ | 449 | | | $ | 903 | |
| | Supplemental cash flow information | | Supplemental cash flow information | |
| Decrease in capital expenditures not paid | | Decrease in capital expenditures not paid | $ | (88) | | | $ | (34) | | | $ | (199) | |
| Increase in DPP | | Increase in DPP | 4,441 | | | 0 | | | 0 | |
| Increase (decrease) in PP&E related to ARO update | | Increase (decrease) in PP&E related to ARO update | 850 | | | 959 | | | (130) | |
See the Combined Notes to Consolidated Financial Statements
218185
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
| | | | | | | | | | | |
| December 31, |
| (In millions) | 2020 | | 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 226 | | | $ | 303 | |
| Restricted cash and cash equivalents | 89 | | | 146 | |
| Accounts receivable | | | |
| Customer accounts receivable | 1,330 | | 2,973 |
| Customer allowance for credit losses | (32) | | (80) |
| Customer accounts receivable, net | 1,298 | | | 2,893 | |
| Other accounts receivable | 352 | | 619 |
| | | |
| Other accounts receivable, net | 352 | | | 619 | |
| Mark-to-market derivative assets | 644 | | | 675 | |
| Receivables from affiliates | 153 | | | 190 | |
| | | |
| Unamortized energy contract assets | 38 | | | 47 | |
| Inventories, net | | | |
| Fossil fuel and emission allowances | 233 | | | 236 | |
| Materials and supplies | 978 | | | 1,026 | |
| | | |
| | | |
| | | |
| Renewable energy credits | 621 | | | 336 | |
| Assets held for sale | 958 | | | 0 | |
| Other | 1,357 | | | 605 | |
| Total current assets | 6,947 | | | 7,076 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $13,370 and $12,017 as of December 31, 2020 and 2019, respectively) | 22,214 | | | 24,193 | |
| Deferred debits and other assets | | | |
| | | |
| Nuclear decommissioning trust funds | 14,464 | | | 13,190 | |
| Investments | 184 | | | 235 | |
| Goodwill | 47 | | | 47 | |
| Mark-to-market derivative assets | 555 | | | 508 | |
| | | |
| Prepaid pension asset | 1,558 | | | 1,438 | |
| | | |
| Unamortized energy contract assets | 293 | | | 336 | |
| Deferred income taxes | 6 | | | 12 | |
| Other | 1,826 | | | 1,960 | |
| Total deferred debits and other assets | 18,933 | | | 17,726 | |
Total assets(a) | $ | 48,094 | | | $ | 48,995 | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 750 |
| | $ | 416 |
|
| Restricted cash and cash equivalents | 153 |
| | 138 |
|
| Accounts receivable, net | | | |
| Customer | 2,941 |
| | 2,697 |
|
| Other | 562 |
| | 321 |
|
| Mark-to-market derivative assets | 804 |
| | 976 |
|
| Receivables from affiliates | 173 |
| | 140 |
|
| Unamortized energy contract assets | 49 |
| | 60 |
|
| Inventories, net | | | |
| Fossil fuel and emission allowances | 251 |
| | 264 |
|
| Materials and supplies | 963 |
| | 937 |
|
| Assets held for sale | 904 |
| | — |
|
| Other | 883 |
| | 933 |
|
| Total current assets | 8,433 |
|
| 6,882 |
|
| Property, plant and equipment, net | 23,981 |
| | 24,906 |
|
| Deferred debits and other assets | | | |
| Nuclear decommissioning trust funds | 11,661 |
| | 13,272 |
|
| Investments | 414 |
| | 433 |
|
| Goodwill | 47 |
| | 47 |
|
| Mark-to-market derivative assets | 452 |
| | 334 |
|
| Prepaid pension asset | 1,421 |
| | 1,502 |
|
| Unamortized energy contract assets | 371 |
| | 395 |
|
| Deferred income taxes | 21 |
| | 16 |
|
| Other | 755 |
| | 670 |
|
| Total deferred debits and other assets | 15,142 |
|
| 16,669 |
|
Total assets(a) | $ | 47,556 |
|
| $ | 48,457 |
|
See the Combined Notes to Consolidated Financial Statements
219186
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
| | | | December 31, | | December 31, |
| (In millions) | 2018 | | 2017 | (In millions) | 2020 | | 2019 |
| LIABILITIES AND EQUITY | | | | LIABILITIES AND EQUITY | | | |
| Current liabilities | | | | Current liabilities | |
| Short-term borrowings | $ | — |
| | $ | 2 |
| Short-term borrowings | $ | 840 | | | $ | 320 | |
| Long-term debt due within one year | 906 |
| | 346 |
| Long-term debt due within one year | 197 | | | 2,624 | |
| Long-term debt to affiliates due within one year | | Long-term debt to affiliates due within one year | 0 | | | 558 | |
| Accounts payable | 1,847 |
| | 1,773 |
| Accounts payable | 1,253 | | | 1,692 | |
| Accrued expenses | 898 |
| | 1,022 |
| Accrued expenses | 788 | | | 786 | |
| Payables to affiliates | 139 |
| | 123 |
| Payables to affiliates | 107 | | | 117 | |
| Borrowings from Exelon intercompany money pool | 100 |
| | 54 |
| Borrowings from Exelon intercompany money pool | 285 | | | 0 | |
| | Mark-to-market derivative liabilities | 449 |
| | 211 |
| Mark-to-market derivative liabilities | 262 | | | 215 | |
| Unamortized energy contract liabilities | 31 |
| | 43 |
| Unamortized energy contract liabilities | 7 | | | 17 | |
| Renewable energy credit obligation | 343 |
| | 352 |
| Renewable energy credit obligation | 661 | | | 443 | |
| Liabilities held for sale | 777 |
| | — |
| Liabilities held for sale | 375 | | | 0 | |
| Other | 279 |
| | 265 |
| Other | 444 | | | 517 | |
| Total current liabilities | 5,769 |
|
| 4,191 |
| Total current liabilities | 5,219 | | | 7,289 | |
| Long-term debt | 6,989 |
| | 7,734 |
| Long-term debt | 5,566 | | | 4,464 | |
| Long-term debt to affiliates | 898 |
| | 910 |
| Long-term debt to affiliates | 324 | | | 328 | |
| | Deferred credits and other liabilities | | | | Deferred credits and other liabilities | |
| Deferred income taxes and unamortized investment tax credits | 3,383 |
| | 3,811 |
| Deferred income taxes and unamortized investment tax credits | 3,656 | | | 3,752 | |
| Asset retirement obligations | 9,450 |
| | 9,844 |
| Asset retirement obligations | 12,054 | | | 10,603 | |
| | Non-pension postretirement benefit obligations | 900 |
| | 916 |
| Non-pension postretirement benefit obligations | 858 | | | 878 | |
| Spent nuclear fuel obligation | 1,171 |
| | 1,147 |
| Spent nuclear fuel obligation | 1,208 | | | 1,199 | |
| | Payables to affiliates | 2,606 |
| | 3,065 |
| Payables to affiliates | 3,017 | | | 3,103 | |
| Mark-to-market derivative liabilities | 252 |
| | 174 |
| Mark-to-market derivative liabilities | 205 | | | 123 | |
| Unamortized energy contract liabilities | 20 |
| | 48 |
| Unamortized energy contract liabilities | 3 | | | 11 | |
| | Other | 610 |
| | 658 |
| Other | 1,308 | | | 1,415 | |
| Total deferred credits and other liabilities | 18,392 |
|
| 19,663 |
| Total deferred credits and other liabilities | 22,309 | | | 21,084 | |
Total liabilities(a) | 32,048 |
|
| 32,498 |
| Total liabilities(a) | 33,418 | | | 33,165 | |
| Commitments and contingencies |
| |
| Commitments and contingencies | 0 | | 0 |
| | Equity | | | | Equity | |
| Member’s equity | | | | Member’s equity | |
| Membership interest | 9,518 |
| | 9,357 |
| Membership interest | 9,624 | | | 9,566 | |
| Undistributed earnings | 3,724 |
| | 4,349 |
| Undistributed earnings | 2,805 | | | 3,950 | |
| Accumulated other comprehensive loss, net | (38 | ) | | (37 | ) | Accumulated other comprehensive loss, net | (30) | | | (32) | |
| Total member’s equity | 13,204 |
|
| 13,669 |
| Total member’s equity | 12,399 | | | 13,484 | |
| Noncontrolling interests | 2,304 |
| | 2,290 |
| Noncontrolling interests | 2,277 | | | 2,346 | |
| Total equity | 15,508 |
|
| 15,959 |
| Total equity | 14,676 | | | 15,830 | |
| Total liabilities and equity | $ | 47,556 |
|
| $ | 48,457 |
| Total liabilities and equity | $ | 48,094 | | | $ | 48,995 | |
__________
| |
(a) | Generation’s consolidated assets include $9,634 million and $9,556 million at December 31, 2018 and 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,480 million and $3,516 million at December 31, 2018 and 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities for additional information. |
(a)Generation’s consolidated assets include $10,182 million and $9,512 million at December 31, 2020 and 2019, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,572 million and $3,429 million at December 31, 2020 and 2019, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 23–Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
220187
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Member’s Equity | | Noncontrolling
Interests | | Total
Equity |
| (In millions) | Membership
Interest | | Undistributed
Earnings | | Accumulated
Other
Comprehensive
Loss, net | |
| Balance, December 31, 2017 | $ | 9,357 | | | $ | 4,349 | | | $ | (37) | | | $ | 2,290 | | | $ | 15,959 | |
| Net income | — | | | 370 | | | — | | | 73 | | | 443 | |
| Sale of noncontrolling interests | 6 | | | — | | | — | | | 0 | | | 6 | |
| | | | | | | | | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | (60) | | | (60) | |
| | | | | | | | | |
| Distributions to member | — | | | (1,001) | | | — | | | — | | | (1,001) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Contributions from member | 155 | | | — | | | — | | | — | | | 155 | |
| Other comprehensive income, net of income taxes | — | | | — | | | 2 | | | 1 | | | 3 | |
| Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard | — | | | 6 | | | (3) | | | — | | | 3 | |
| Balance, December 31, 2018 | $ | 9,518 | | | $ | 3,724 | | | $ | (38) | | | $ | 2,304 | | | $ | 15,508 | |
| Net income | — | | | 1,125 | | | — | | | 92 | | | 1,217 | |
| Sale of noncontrolling interests | 7 | | | — | | | — | | | 0 | | | 7 | |
| | | | | | | | | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | (48) | | | (48) | |
| | | | | | | | | |
| Distributions to member | — | | | (899) | | | — | | | — | | | (899) | |
| Contributions from member | 41 | | | — | | | — | | | — | | | 41 | |
| Other comprehensive income (loss), net of income taxes | — | | | — | | | 6 | | | (2) | | | 4 | |
| | | | | | | | | |
| | | | | | | | | |
| Balance, December 31, 2019 | $ | 9,566 | | | $ | 3,950 | | | $ | (32) | | | $ | 2,346 | | | $ | 15,830 | |
| Net income | — | | | 589 | | | — | | | (10) | | | 579 | |
| Sale of noncontrolling interests | 3 | | | — | | | — | | | 0 | | | 3 | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | (59) | | | (59) | |
| Distribution to member of deferred taxes associated with net retirement benefit obligation | (9) | | | — | | | — | | | — | | | (9) | |
| | | | | | | | | |
| Distributions to member | — | | | (1,734) | | | — | | | — | | | (1,734) | |
| Contributions from member | 64 | | | — | | | — | | | — | | | 64 | |
| Other comprehensive income, net of income taxes | — | | | — | | | 2 | | | 0 | | | 2 | |
| | | | | | | | | |
| Balance, December 31, 2020 | $ | 9,624 | | | $ | 2,805 | | | $ | (30) | | | $ | 2,277 | | | $ | 14,676 | |
|
| | | | | | | | | | | | | | | | | | | |
| Member’s Equity |
| Noncontrolling
Interests |
| Total
Equity |
| (In millions) | Membership
Interest |
| Undistributed
Earnings |
| Accumulated
Other
Comprehensive
Loss, net |
|
| Balance, December 31, 2015 | $ | 8,997 |
| | $ | 2,737 |
| | $ | (63 | ) | | $ | 1,307 |
| | $ | 12,978 |
|
| Net income | — |
|
| 483 |
|
| — |
|
| 67 |
|
| 550 |
|
| Sale of noncontrolling interests | (4 | ) |
| — |
|
| — |
|
| 243 |
|
| 239 |
|
| Adjustment of contingently redeemable noncontrolling interests due to release of contingency | — |
| | — |
| | — |
| | 157 |
| | 157 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | 5 |
| | 5 |
|
| Contributions from member | 268 |
| | — |
| | — |
| | — |
| | 268 |
|
| Distributions to member | — |
| | (922 | ) | | — |
| | — |
| | (922 | ) |
| Other comprehensive income, net of income taxes | — |
|
| — |
|
| 9 |
|
| — |
|
| 9 |
|
| Balance, December 31, 2016 | $ | 9,261 |
|
| $ | 2,298 |
|
| $ | (54 | ) |
| $ | 1,779 |
|
| $ | 13,284 |
|
| Net income | — |
|
| 2,710 |
|
| — |
|
| 88 |
|
| 2,798 |
|
| Sale of noncontrolling interests | (36 | ) | | — |
| | — |
| | 443 |
| | 407 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | (18 | ) | | (18 | ) |
| Distribution of net retirement benefit obligation to member | 33 |
|
| — |
|
| — |
|
| — |
|
| 33 |
|
| Contributions from member | 99 |
| | — |
| | — |
| | — |
| | 99 |
|
| Distributions to member | — |
|
| (659 | ) |
| — |
|
| — |
|
| (659 | ) |
| Other comprehensive income (loss), net of income taxes | — |
|
| — |
|
| 17 |
|
| (2 | ) |
| 15 |
|
| Balance, December 31, 2017 | $ | 9,357 |
|
| $ | 4,349 |
|
| $ | (37 | ) |
| $ | 2,290 |
|
| $ | 15,959 |
|
| Net income | — |
| | 370 |
| | — |
| | 73 |
| | 443 |
|
| Sale of noncontrolling interests | 6 |
| | — |
| | — |
| | — |
| | 6 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | (60 | ) | | (60 | ) |
| Contributions from member | 155 |
| | — |
| | — |
| | — |
| | 155 |
|
| Distributions to member | — |
| | (1,001 | ) | | — |
| | — |
| | (1,001 | ) |
| Other comprehensive income, net of income taxes | — |
| | — |
| | 2 |
| | 1 |
| | 3 |
|
| Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard | — |
| | 6 |
| | (3 | ) | | — |
| | 3 |
|
| Balance, December 31, 2018 | $ | 9,518 |
| | $ | 3,724 |
| | $ | (38 | ) | | $ | 2,304 |
| | $ | 15,508 |
|
See the Combined Notes to Consolidated Financial Statements
221188
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Operating revenues | | | | | |
| Electric operating revenues | $ | 5,914 | | | $ | 5,850 | | | $ | 5,884 | |
| Revenues from alternative revenue programs | (47) | | | (133) | | | (29) | |
| Operating revenues from affiliates | 37 | | | 30 | | | 27 | |
| Total operating revenues | 5,904 | | | 5,747 | | | 5,882 | |
| Operating expenses | | | | | |
| Purchased power | 1,653 | | | 1,565 | | | 1,626 | |
| Purchased power from affiliates | 345 | | | 376 | | | 529 | |
| Operating and maintenance | 1,231 | | | 1,041 | | | 1,068 | |
| Operating and maintenance from affiliates | 289 | | | 264 | | | 267 | |
| Depreciation and amortization | 1,133 | | | 1,033 | | | 940 | |
| Taxes other than income taxes | 299 | | | 301 | | | 311 | |
| Total operating expenses | 4,950 | | | 4,580 | | | 4,741 | |
| Gain on sales of assets | 0 | | | 4 | | | 5 | |
| Operating income | 954 | | | 1,171 | | | 1,146 | |
| Other income and (deductions) | | | | | |
| Interest expense, net | (369) | | | (346) | | | (334) | |
| Interest expense to affiliates | (13) | | | (13) | | | (13) | |
| Other, net | 43 | | | 39 | | | 33 | |
| Total other income and (deductions) | (339) | | | (320) | | | (314) | |
| Income before income taxes | 615 | | | 851 | | | 832 | |
| Income taxes | 177 | | | 163 | | | 168 | |
| Net income | $ | 438 | | | $ | 688 | | | $ | 664 | |
| | | | | |
| | | | | |
| | | | | |
| Comprehensive income | $ | 438 | | | $ | 688 | | | $ | 664 | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Operating revenues | | | | | |
| Electric operating revenues | $ | 5,884 |
| | $ | 5,478 |
| | $ | 5,263 |
|
| Revenues from alternative revenue programs | (29 | ) | | 43 |
| | (24 | ) |
| Operating revenues from affiliates | 27 |
| | 15 |
| | 15 |
|
| Total operating revenues | 5,882 |
| | 5,536 |
| | 5,254 |
|
| Operating expenses | | | | | |
| Purchased power | 1,626 |
| | 1,533 |
| | 1,411 |
|
| Purchased power from affiliates | 529 |
| | 108 |
| | 47 |
|
| Operating and maintenance | 1,068 |
| | 1,157 |
| | 1,303 |
|
| Operating and maintenance from affiliates | 267 |
| | 270 |
| | 227 |
|
| Depreciation and amortization | 940 |
| | 850 |
| | 775 |
|
| Taxes other than income | 311 |
| | 296 |
| | 293 |
|
| Total operating expenses | 4,741 |
| | 4,214 |
| | 4,056 |
|
| Gain on sales of assets | 5 |
| | 1 |
| | 7 |
|
| Operating income | 1,146 |
| | 1,323 |
| | 1,205 |
|
| Other income and (deductions) | | | | | |
| Interest expense, net | (334 | ) | | (348 | ) | | (448 | ) |
| Interest expense to affiliates | (13 | ) | | (13 | ) | | (13 | ) |
| Other, net | 33 |
| | 22 |
| | (65 | ) |
| Total other income and (deductions) | (314 | ) | | (339 | ) | | (526 | ) |
| Income before income taxes | 832 |
| | 984 |
| | 679 |
|
| Income taxes | 168 |
| | 417 |
| | 301 |
|
| Net income | $ | 664 |
| | $ | 567 |
| | $ | 378 |
|
| Comprehensive income | $ | 664 |
| | $ | 567 |
| | $ | 378 |
|
See the Combined Notes to Consolidated Financial Statements
222189
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Cash Flows
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 438 | | | $ | 688 | | | $ | 664 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | |
| Depreciation and amortization | 1,133 | | | 1,033 | | | 940 | |
| | | | | |
| Deferred income taxes and amortization of investment tax credits | 228 | | | 109 | | | 259 | |
| Other non-cash operating activities | 202 | | | 265 | | | 242 | |
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | (10) | | | (34) | | | (136) | |
| Receivables from and payables to affiliates, net | (1) | | | (12) | | | 26 | |
| Inventories | (13) | | | (16) | | | 1 | |
| Accounts payable and accrued expenses | 63 | | | (51) | | | 70 | |
| Counterparty received (posted), net | 14 | | | 48 | | | 11 | |
| Income taxes | 8 | | | 95 | | | 62 | |
| Pension and non-pension postretirement benefit contributions | (148) | | | (77) | | | (42) | |
| Other assets and liabilities | (590) | | | (345) | | | (348) | |
| Net cash flows provided by operating activities | 1,324 | | | 1,703 | | | 1,749 | |
| Cash flows from investing activities | | | | | |
| Capital expenditures | (2,217) | | | (1,915) | | | (2,126) | |
| | | | | |
| | | | | |
| Other investing activities | 2 | | | 29 | | | 29 | |
| Net cash flows used in investing activities | (2,215) | | | (1,886) | | | (2,097) | |
| Cash flows from financing activities | | | | | |
| Changes in short-term borrowings | 193 | | | 130 | | | 0 | |
| Issuance of long-term debt | 1,000 | | | 700 | | | 1,350 | |
| Retirement of long-term debt | (500) | | | (300) | | | (840) | |
| Dividends paid on common stock | (499) | | | (508) | | | (459) | |
| Contributions from parent | 712 | | | 250 | | | 500 | |
| Other financing activities | (13) | | | (16) | | | (17) | |
| Net cash flows provided by financing activities | 893 | | | 256 | | | 534 | |
| Increase in cash, restricted cash, and cash equivalents | 2 | | | 73 | | | 186 | |
| Cash, restricted cash, and cash equivalents at beginning of period | 403 | | | 330 | | | 144 | |
| Cash, restricted cash, and cash equivalents at end of period | $ | 405 | | | $ | 403 | | | $ | 330 | |
| | | | | |
| Supplemental cash flow information | | | | | |
| Increase (decrease) in capital expenditures not paid | $ | 109 | | | $ | (37) | | | $ | 11 | |
| | | | | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 664 |
| | $ | 567 |
| | $ | 378 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | |
| Depreciation, amortization and accretion | 940 |
| | 850 |
| | 775 |
|
| Deferred income taxes and amortization of investment tax credits | 259 |
| | 659 |
| | 439 |
|
| Other non-cash operating activities | 242 |
| | 164 |
| | 215 |
|
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | (136 | ) | | (59 | ) | | (25 | ) |
| Receivables from and payables to affiliates, net | 26 |
| | 8 |
| | 3 |
|
| Inventories | 1 |
| | 4 |
| | 1 |
|
| Accounts payable and accrued expenses | 70 |
| | (297 | ) | | 339 |
|
| Counterparty collateral received (posted), net and cash deposits | 11 |
| | (26 | ) | | 7 |
|
| Income taxes | 62 |
| | (308 | ) | | 306 |
|
| Pension and non-pension postretirement benefit contributions | (42 | ) | | (41 | ) | | (38 | ) |
| Other assets and liabilities | (348 | ) | | 6 |
| | 105 |
|
| Net cash flows provided by operating activities | 1,749 |
| | 1,527 |
| | 2,505 |
|
| Cash flows from investing activities | | | | | |
| Capital expenditures | (2,126 | ) | | (2,250 | ) | | (2,734 | ) |
| Other investing activities | 29 |
| | 20 |
| | 49 |
|
| Net cash flows used in investing activities | (2,097 | ) | | (2,230 | ) | | (2,685 | ) |
| Cash flows from financing activities | | | | | |
| Changes in short-term borrowings | — |
| | — |
| | (294 | ) |
| Issuance of long-term debt | 1,350 |
| | 1,000 |
| | 1,200 |
|
| Retirement of long-term debt | (840 | ) | | (425 | ) | | (665 | ) |
| Contributions from parent | 500 |
| | 651 |
| | 315 |
|
| Dividends paid on common stock | (459 | ) | | (422 | ) | | (369 | ) |
| Other financing activities | (17 | ) | | (15 | ) | | (18 | ) |
| Net cash flows provided by financing activities | 534 |
| | 789 |
| | 169 |
|
| Increase (decrease) in cash, cash equivalents and restricted cash | 186 |
| | 86 |
| | (11 | ) |
| Cash, cash equivalents and restricted cash at beginning of period | 144 |
| | 58 |
| | 69 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 330 |
| | $ | 144 |
| | $ | 58 |
|
See the Combined Notes to Consolidated Financial Statements
223190
Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
| | | | | | | | | | | |
| December 31, |
| (In millions) | 2020 | | 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 83 | | | $ | 90 | |
| Restricted cash and cash equivalents | 279 | | | 150 | |
| Accounts receivable | | | |
| Customer accounts receivable | 656 | | 604 |
| Customer allowance for credit losses | (97) | | (59) |
| Customer accounts receivable, net | 559 | | | 545 | |
| Other accounts receivable | 239 | | 306 |
| Other allowance for credit losses | (21) | | (20) |
| Other accounts receivable, net | 218 | | | 286 | |
| Receivables from affiliates | 22 | | | 28 | |
| Inventories, net | 170 | | | 159 | |
| | | |
| | | |
| Regulatory assets | 279 | | | 281 | |
| Other | 49 | | | 44 | |
| Total current assets | 1,659 | | | 1,583 | |
Property, plant, and equipment (net of accumulated depreciation and amortization of $5,672 and $5,168 as of December 31, 2020 and December 31, 2019, respectively) | 24,557 | | | 23,107 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 1,749 | | | 1,480 | |
| Investments | 6 | | | 6 | |
| | | |
| Goodwill | 2,625 | | | 2,625 | |
| Receivables from affiliates | 2,541 | | | 2,622 | |
| Prepaid pension asset | 1,022 | | | 995 | |
| Other | 307 | | | 347 | |
| Total deferred debits and other assets | 8,250 | | | 8,075 | |
| Total assets | $ | 34,466 | | | $ | 32,765 | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 135 |
| | $ | 76 |
|
| Restricted cash and cash equivalents | 29 |
| | 5 |
|
| Accounts receivable, net | | | |
| Customer | 539 |
| | 559 |
|
| Other | 320 |
| | 266 |
|
| Receivables from affiliates | 20 |
| | 13 |
|
| Inventories, net | 148 |
| | 152 |
|
| Regulatory assets | 293 |
| | 225 |
|
| Other | 86 |
| | 68 |
|
| Total current assets | 1,570 |
| | 1,364 |
|
| Property, plant and equipment, net | 22,058 |
| | 20,723 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 1,307 |
| | 1,054 |
|
| Investments | 6 |
| | 6 |
|
| Goodwill | 2,625 |
| | 2,625 |
|
| Receivables from affiliates | 2,217 |
| | 2,528 |
|
| Prepaid pension asset | 1,035 |
| | 1,188 |
|
| Other | 395 |
| | 238 |
|
| Total deferred debits and other assets | 7,585 |
| | 7,639 |
|
| Total assets | $ | 31,213 |
| | $ | 29,726 |
|
See the Combined Notes to Consolidated Financial Statements
224191
Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
| | | | December 31, | | December 31, |
| (In millions) | 2018 | | 2017 | (In millions) | 2020 | | 2019 |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities | | | | Current liabilities | |
| Short-term borrowings | | Short-term borrowings | $ | 323 | | | $ | 130 | |
| Long-term debt due within one year | $ | 300 |
| | $ | 840 |
| Long-term debt due within one year | 350 | | | 500 | |
| Accounts payable | 607 |
| | 568 |
| Accounts payable | 683 | | | 527 | |
| Accrued expenses | 373 |
| | 327 |
| Accrued expenses | 390 | | | 385 | |
| Payables to affiliates | 119 |
| | 74 |
| Payables to affiliates | 96 | | | 103 | |
| Customer deposits | 111 |
| | 112 |
| Customer deposits | 86 | | | 118 | |
| Regulatory liabilities | 293 |
| | 249 |
| Regulatory liabilities | 289 | | | 200 | |
| Mark-to-market derivative liability | 26 |
| | 21 |
| |
| Mark-to-market derivative liabilities | | Mark-to-market derivative liabilities | 33 | | | 32 | |
| | Other | 96 |
| | 103 |
| Other | 143 | | | 122 | |
| Total current liabilities | 1,925 |
| | 2,294 |
| Total current liabilities | 2,393 | | | 2,117 | |
| Long-term debt | 7,801 |
| | 6,761 |
| Long-term debt | 8,633 | | | 7,991 | |
| Long-term debt to financing trust | 205 |
| | 205 |
| |
| Long-term debt to financing trusts | | Long-term debt to financing trusts | 205 | | | 205 | |
| Deferred credits and other liabilities | | | | Deferred credits and other liabilities | |
| Deferred income taxes and unamortized investment tax credits | 3,813 |
| | 3,469 |
| Deferred income taxes and unamortized investment tax credits | 4,341 | | | 4,021 | |
| Asset retirement obligations | 118 |
| | 111 |
| Asset retirement obligations | 126 | | | 128 | |
| Non-pension postretirement benefits obligations | 201 |
| | 219 |
| Non-pension postretirement benefits obligations | 173 | | | 180 | |
| Regulatory liabilities | 6,050 |
| | 6,328 |
| Regulatory liabilities | 6,403 | | | 6,542 | |
| Mark-to-market derivative liability | 223 |
| | 235 |
| |
| Mark-to-market derivative liabilities | | Mark-to-market derivative liabilities | 268 | | | 269 | |
| Other | 630 |
| | 562 |
| Other | 595 | | | 635 | |
| Total deferred credits and other liabilities | 11,035 |
| | 10,924 |
| Total deferred credits and other liabilities | 11,906 | | | 11,775 | |
| Total liabilities | 20,966 |
| | 20,184 |
| Total liabilities | 23,137 | | | 22,088 | |
| Commitments and contingencies |
| |
| Commitments and contingencies | 0 | | 0 |
| Shareholders’ equity | | | | Shareholders’ equity | |
| Common stock | 1,588 |
| | 1,588 |
| |
Common stock ($12.50 par value, 250 shares authorized, 127 shares outstanding at December 31, 2020 and 2019) | | Common stock ($12.50 par value, 250 shares authorized, 127 shares outstanding at December 31, 2020 and 2019) | 1,588 | | | 1,588 | |
| Other paid-in capital | 7,322 |
| | 6,822 |
| Other paid-in capital | 8,285 | | | 7,572 | |
| Retained deficit unappropriated | (1,639 | ) | | (1,639 | ) | Retained deficit unappropriated | (1,639) | | | (1,639) | |
| Retained earnings appropriated | 2,976 |
| | 2,771 |
| Retained earnings appropriated | 3,095 | | | 3,156 | |
| Total shareholders’ equity | 10,247 |
| | 9,542 |
| Total shareholders’ equity | 11,329 | | | 10,677 | |
| Total liabilities and shareholders’ equity | $ | 31,213 |
| | $ | 29,726 |
| Total liabilities and shareholders’ equity | $ | 34,466 | | | $ | 32,765 | |
See the Combined Notes to Consolidated Financial Statements
225192
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders’ Equity
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Common
Stock | | Other
Paid-In
Capital | | Retained Deficit
Unappropriated | | Retained
Earnings
Appropriated | | Total
Shareholders’
Equity |
| Balance, December 31, 2017 | $ | 1,588 | | | $ | 6,822 | | | $ | (1,639) | | | $ | 2,771 | | | $ | 9,542 | |
| Net income | — | | | — | | | 664 | | | — | | | 664 | |
| Appropriation of retained earnings for future dividends | — | | | — | | | (664) | | | 664 | | | 0 | |
| Common stock dividends | — | | | — | | | — | | | (459) | | | (459) | |
| Contributions from parent | — | | | 500 | | | — | | | — | | | 500 | |
| | | | | | | | | |
| Balance, December 31, 2018 | $ | 1,588 | | | $ | 7,322 | | | $ | (1,639) | | | $ | 2,976 | | | $ | 10,247 | |
| Net income | — | | | — | | | 688 | | | — | | | 688 | |
| Appropriation of retained earnings for future dividends | — | | | — | | | (688) | | | 688 | | | 0 | |
| Common stock dividends | — | | | — | | | — | | | (508) | | | (508) | |
| Contributions from parent | — | | | 250 | | | — | | | — | | | 250 | |
| | | | | | | | | |
| Balance, December 31, 2019 | $ | 1,588 | | | $ | 7,572 | | | $ | (1,639) | | | $ | 3,156 | | | $ | 10,677 | |
| Net income | — | | | — | | | 438 | | | — | | | 438 | |
| Appropriation of retained earnings for future dividends | — | | | — | | | (438) | | | 438 | | | 0 | |
| Common stock dividends | — | | | — | | | — | | | (499) | | | (499) | |
| Contributions from parent | — | | | 713 | | | — | | | — | | | 713 | |
| | | | | | | | | |
| Balance, December 31, 2020 | $ | 1,588 | | | $ | 8,285 | | | $ | (1,639) | | | $ | 3,095 | | | $ | 11,329 | |
|
| | | | | | | | | | | | | | | | | | | |
| (In millions) | Common Stock | | Other Paid-In Capital | | Retained Deficit Unappropriated | | Retained Earnings Appropriated | | Total Shareholders’ Equity |
| Balance, December 31, 2015 | $ | 1,588 |
| | $ | 5,677 |
| | $ | (1,639 | ) | | $ | 2,617 |
| | $ | 8,243 |
|
| Net income | — |
| | — |
| | 378 |
| | — |
| | 378 |
|
| Common stock dividends | — |
| | — |
| | — |
| | (369 | ) | | (369 | ) |
| Contribution from parent | — |
| | 315 |
| | — |
| | — |
| | 315 |
|
| Parent tax matter indemnification | — |
| | 158 |
| | — |
| | — |
| | 158 |
|
| Appropriation of retained earnings for future dividends | — |
| | — |
| | (378 | ) | | 378 |
| | — |
|
| Balance, December 31, 2016 | $ | 1,588 |
| | $ | 6,150 |
| | $ | (1,639 | ) | | $ | 2,626 |
| | $ | 8,725 |
|
| Net income | — |
| | — |
| | 567 |
| | — |
| | 567 |
|
| Common stock dividends | — |
| | — |
| | — |
| | (422 | ) | | (422 | ) |
| Contributions from parent | — |
| | 651 |
| | — |
| | — |
| | 651 |
|
| Parent tax matter indemnification | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Appropriation of retained earnings for future dividends | — |
| | — |
| | (567 | ) | | 567 |
| | — |
|
| Balance, December 31, 2017 | $ | 1,588 |
| | $ | 6,822 |
| | $ | (1,639 | ) | | $ | 2,771 |
| | $ | 9,542 |
|
| Net income | — |
| | — |
| | 664 |
| | — |
| | 664 |
|
| Common stock dividends | — |
| | — |
| | — |
| | (459 | ) | | (459 | ) |
| Contributions from parent | — |
| | 500 |
| | — |
| | — |
| | 500 |
|
| Appropriation of retained earnings for future dividends | — |
| | — |
| | (664 | ) | | 664 |
| | — |
|
| Balance, December 31, 2018 | $ | 1,588 |
| | $ | 7,322 |
| | $ | (1,639 | ) | | $ | 2,976 |
| | $ | 10,247 |
|
See the Combined Notes to Consolidated Financial Statements
226193
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Operating revenues | | | | | |
| Electric operating revenues | $ | 2,519 | | | $ | 2,505 | | | $ | 2,469 | |
| Natural gas operating revenues | 514 | | | 610 | | | 568 | |
| Revenues from alternative revenue programs | 16 | | | (21) | | | (7) | |
| Operating revenues from affiliates | 9 | | | 6 | | | 8 | |
| Total operating revenues | 3,058 | | | 3,100 | | | 3,038 | |
| Operating expenses | | | | | |
| Purchased power | 645 | | | 610 | | | 734 | |
| Purchased fuel | 185 | | | 262 | | | 230 | |
| Purchased power from affiliates | 188 | | | 157 | | | 126 | |
| Operating and maintenance | 816 | | | 707 | | | 742 | |
| Operating and maintenance from affiliates | 159 | | | 154 | | | 156 | |
| Depreciation and amortization | 347 | | | 333 | | | 301 | |
| Taxes other than income taxes | 172 | | | 165 | | | 163 | |
| Total operating expenses | 2,512 | | | 2,388 | | | 2,452 | |
| Gain on sales of assets | 0 | | | 1 | | | 1 | |
| Operating income | 546 | | | 713 | | | 587 | |
| Other income and (deductions) | | | | | |
| Interest expense, net | (136) | | | (124) | | | (115) | |
| Interest expense to affiliates, net | (11) | | | (12) | | | (14) | |
| Other, net | 18 | | | 16 | | | 8 | |
| Total other income and (deductions) | (129) | | | (120) | | | (121) | |
| Income before income taxes | 417 | | | 593 | | | 466 | |
| Income taxes | (30) | | | 65 | | | 6 | |
| | | | | |
| | | | | |
| Net income | $ | 447 | | | $ | 528 | | | $ | 460 | |
| Comprehensive income | $ | 447 | | | $ | 528 | | | $ | 460 | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Operating revenues | | | | | |
| Electric operating revenues | $ | 2,469 |
| | $ | 2,369 |
| | $ | 2,524 |
|
| Natural gas operating revenues | 568 |
| | 494 |
| | 462 |
|
| Revenues from alternative revenue programs | (7 | ) | | — |
| | — |
|
| Operating revenues from affiliates | 8 |
| | 7 |
| | 8 |
|
| Total operating revenues | 3,038 |
|
| 2,870 |
|
| 2,994 |
|
| Operating expenses | | | | | |
| Purchased power | 734 |
| | 648 |
| | 598 |
|
| Purchased fuel | 230 |
| | 186 |
| | 162 |
|
| Purchased power from affiliates | 126 |
| | 135 |
| | 287 |
|
| Operating and maintenance | 742 |
| | 657 |
| | 665 |
|
| Operating and maintenance from affiliates | 156 |
| | 149 |
| | 146 |
|
| Depreciation and amortization | 301 |
| | 286 |
| | 270 |
|
| Taxes other than income | 163 |
| | 154 |
| | 164 |
|
| Total operating expenses | 2,452 |
|
| 2,215 |
|
| 2,292 |
|
| Gain on sales of assets | 1 |
| | — |
| | — |
|
| Operating income | 587 |
|
| 655 |
|
| 702 |
|
| Other income and (deductions) | | | | | |
| Interest expense, net | (115 | ) | | (115 | ) | | (111 | ) |
| Interest expense to affiliates, net | (14 | ) | | (11 | ) | | (12 | ) |
| Other, net | 8 |
| | 9 |
| | 8 |
|
| Total other income and (deductions) | (121 | ) |
| (117 | ) |
| (115 | ) |
| Income before income taxes | 466 |
|
| 538 |
|
| 587 |
|
| Income taxes | 6 |
| | 104 |
| | 149 |
|
| Net income | $ | 460 |
|
| $ | 434 |
|
| $ | 438 |
|
| Comprehensive income | $ | 460 |
|
| $ | 434 |
|
| $ | 438 |
|
See the Combined Notes to Consolidated Financial Statements
227194
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Cash Flows
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 447 | | | $ | 528 | | | $ | 460 | |
Adjustments to reconcile net income to net cash flows provided by
operating activities: | | | | | |
| Depreciation and amortization | 347 | | | 333 | | | 301 | |
| Gain on sale of assets | 0 | | | (1) | | | 0 | |
Deferred income taxes and amortization of investment tax
credits | (23) | | | 20 | | | (5) | |
| Other non-cash operating activities | 24 | | | 38 | | | 51 | |
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | (88) | | | (29) | | | (74) | |
| Receivables from and payables to affiliates, net | (6) | | | (5) | | | 7 | |
| Inventories | (1) | | | 4 | | | (14) | |
| Accounts payable and accrued expenses | 63 | | | (11) | | | (3) | |
| Income taxes | 31 | | | (34) | | | 15 | |
| Pension and non-pension postretirement benefit contributions | (18) | | | (28) | | | (28) | |
| Other assets and liabilities | 1 | | | (64) | | | 29 | |
| Net cash flows provided by operating activities | 777 | | | 751 | | | 739 | |
| Cash flows from investing activities | | | | | |
| Capital expenditures | (1,147) | | | (939) | | | (849) | |
| Changes in Exelon intercompany money pool | 68 | | | (68) | | | 0 | |
| | | | | |
| Other investing activities | 7 | | | (1) | | | 9 | |
| Net cash flows used in investing activities | (1,072) | | | (1,008) | | | (840) | |
| Cash flows from financing activities | | | | | |
| | | | | |
| Issuance of long-term debt | 350 | | | 325 | | | 700 | |
| Retirement of long-term debt | 0 | | | 0 | | | (500) | |
| Dividends paid on common stock | (340) | | | (358) | | | (306) | |
| Contributions from parent | 248 | | | 188 | | | 89 | |
| Changes in Exelon intercompany money pool | 40 | | | 0 | | | 0 | |
| | | | | |
| | | | | |
| Other financing activities | (4) | | | (6) | | | (22) | |
| Net cash flows provided by (used in) financing activities | 294 | | | 149 | | | (39) | |
| Decrease in cash, restricted cash, and cash equivalents | (1) | | | (108) | | | (140) | |
| Cash, restricted cash, and cash equivalents at beginning of period | 27 | | | 135 | | | 275 | |
| Cash, restricted cash, and cash equivalents at end of period | $ | 26 | | | $ | 27 | | | $ | 135 | |
| | | | | |
| Supplemental cash flow information | | | | | |
| Increase (decrease) in capital expenditures not paid | $ | 55 | | | $ | 40 | | | $ | (12) | |
| | | | | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 460 |
| | $ | 434 |
| | $ | 438 |
|
Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | |
| Depreciation, amortization and accretion | 301 |
| | 286 |
| | 270 |
|
Deferred income taxes and amortization of investment tax credits | (5 | ) | | 19 |
| | 78 |
|
| Other non-cash operating activities | 51 |
| | 54 |
| | 65 |
|
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | (74 | ) | | (44 | ) | | (71 | ) |
| Receivables from and payables to affiliates, net | 7 |
| | (6 | ) | | 6 |
|
| Inventories | (14 | ) | | 1 |
| | 6 |
|
| Accounts payable and accrued expenses | (3 | ) | | 6 |
| | 67 |
|
| Income taxes | 15 |
| | 34 |
| | 8 |
|
Pension and non-pension postretirement benefit contributions | (28 | ) | | (24 | ) | | (30 | ) |
| Other assets and liabilities | 29 |
| | (5 | ) | | (8 | ) |
| Net cash flows provided by operating activities | 739 |
|
| 755 |
|
| 829 |
|
| Cash flows from investing activities | | | | | |
| Capital expenditures | (849 | ) | | (732 | ) | | (686 | ) |
| Changes in intercompany money pool | — |
| | 131 |
| | (131 | ) |
| Other investing activities | 9 |
| | 4 |
| | 20 |
|
| Net cash flows used in investing activities | (840 | ) |
| (597 | ) |
| (797 | ) |
| Cash flows from financing activities | | | | | |
| Issuance of long-term debt | 700 |
| | 325 |
| | 300 |
|
| Retirement of long-term debt | (500 | ) | | — |
| | (300 | ) |
| Contributions from parent | 89 |
| | 16 |
| | 18 |
|
| Dividends paid on common stock | (306 | ) | | (288 | ) | | (277 | ) |
| Other financing activities | (22 | ) | | (3 | ) | | (4 | ) |
| Net cash flows (used in) provided by financing activities | (39 | ) |
| 50 |
|
| (263 | ) |
| (Decrease) increase in cash, cash equivalents and restricted cash | (140 | ) | | 208 |
| | (231 | ) |
| Cash, cash equivalents and restricted cash at beginning of period | 275 |
| | 67 |
| | 298 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 135 |
|
| $ | 275 |
|
| $ | 67 |
|
See the Combined Notes to Consolidated Financial Statements
228195
PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
| | | | | | | | | | | |
| December 31, |
| (In millions) | 2020 | | 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 19 | | | $ | 21 | |
| Restricted cash and cash equivalents | 7 | | | 6 | |
| Accounts receivable | | | |
| Customer accounts receivable | 511 | | 412 |
| Customer allowance for credit losses | (116) | | (55) |
| Customer accounts receivable, net | 395 | | | 357 | |
| Other accounts receivable | 130 | | 145 |
| Other allowance for credit losses | (8) | | (7) |
| Other accounts receivable, net | 122 | | | 138 | |
| Receivables from affiliates | 2 | | | 1 | |
| Receivable from Exelon intercompany money pool | 0 | | | 68 | |
| Inventories, net | | | |
| Fossil fuel | 33 | | | 36 | |
| Materials and supplies | 38 | | | 35 | |
| | | |
| | | |
| Regulatory assets | 25 | | | 41 | |
| Other | 21 | | | 19 | |
| Total current assets | 662 | | | 722 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $3,843 and $3,718 as of December 31, 2020 and 2019, respectively) | 10,181 | | | 9,292 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 776 | | | 554 | |
| Investments | 30 | | | 27 | |
| | | |
| Receivables from affiliates | 475 | | | 480 | |
| Prepaid pension asset | 375 | | | 365 | |
| Other | 32 | | | 29 | |
| Total deferred debits and other assets | 1,688 | | | 1,455 | |
| Total assets | $ | 12,531 | | | $ | 11,469 | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 130 |
| | $ | 271 |
|
| Restricted cash and cash equivalents | 5 |
| | 4 |
|
| Accounts receivable, net | | | |
| Customer | 321 |
| | 327 |
|
| Other | 151 |
| | 105 |
|
| Inventories, net | | | |
| Fossil fuel | 38 |
| | 31 |
|
| Materials and supplies | 37 |
| | 30 |
|
| Prepaid utility taxes | — |
| | 8 |
|
| Regulatory assets | 81 |
| | 29 |
|
| Other | 19 |
| | 17 |
|
| Total current assets | 782 |
|
| 822 |
|
| Property, plant and equipment, net | 8,610 |
| | 8,053 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 460 |
| | 381 |
|
| Investments | 25 |
| | 25 |
|
| Receivables from affiliates | 389 |
| | 537 |
|
| Prepaid pension asset | 349 |
| | 340 |
|
| Other | 27 |
| | 12 |
|
| Total deferred debits and other assets | 1,250 |
|
| 1,295 |
|
| Total assets | $ | 10,642 |
|
| $ | 10,170 |
|
See the Combined Notes to Consolidated Financial Statements
229196
PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
| | | | | | | | | | | |
| December 31, |
| (In millions) | 2020 | | 2019 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| | | |
| Long-term debt due within one year | $ | 300 | | | $ | 0 | |
| Accounts payable | 479 | | | 387 | |
| Accrued expenses | 129 | | | 101 | |
| Payables to affiliates | 50 | | | 55 | |
| Borrowings from Exelon intercompany money pool | 40 | | | 0 | |
| Customer deposits | 59 | | | 69 | |
| Regulatory liabilities | 121 | | | 91 | |
| Other | 30 | | | 19 | |
| Total current liabilities | 1,208 | | | 722 | |
| Long-term debt | 3,453 | | | 3,405 | |
| Long-term debt to financing trusts | 184 | | | 184 | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 2,242 | | | 2,080 | |
| Asset retirement obligations | 29 | | | 28 | |
| Non-pension postretirement benefits obligations | 286 | | | 288 | |
| Regulatory liabilities | 503 | | | 510 | |
| Other | 93 | | | 74 | |
| Total deferred credits and other liabilities | 3,153 | | | 2,980 | |
| Total liabilities | 7,998 | | | 7,291 | |
| Commitments and contingencies | 0 | | 0 |
| | | |
| Shareholder's equity | | | |
| Common stock (NaN par value, 500 shares authorized, 170 shares outstanding at December 31, 2020 and 2019) | 3,014 | | | 2,766 | |
| Retained earnings | 1,519 | | | 1,412 | |
| | | |
| Total shareholder's equity | 4,533 | | | 4,178 | |
| Total liabilities and shareholder's equity | $ | 12,531 | | | $ | 11,469 | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Long-term debt due within one year | $ | — |
| | $ | 500 |
|
| Accounts payable | 370 |
| | 370 |
|
| Accrued expenses | 113 |
| | 114 |
|
| Payables to affiliates | 59 |
| | 53 |
|
| Customer deposits | 68 |
| | 66 |
|
| Regulatory liabilities | 175 |
| | 141 |
|
| Other | 24 |
| | 23 |
|
| Total current liabilities | 809 |
|
| 1,267 |
|
| Long-term debt | 3,084 |
| | 2,403 |
|
| Long-term debt to financing trusts | 184 |
| | 184 |
|
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 1,933 |
| | 1,789 |
|
| Asset retirement obligations | 27 |
| | 27 |
|
| Non-pension postretirement benefits obligations | 288 |
| | 288 |
|
| Regulatory liabilities | 421 |
| | 549 |
|
| Other | 76 |
| | 86 |
|
| Total deferred credits and other liabilities | 2,745 |
|
| 2,739 |
|
| Total liabilities | 6,822 |
|
| 6,593 |
|
| Commitments and contingencies |
| |
|
| Shareholder's equity | | | |
| Common stock | 2,578 |
| | 2,489 |
|
| Retained earnings | 1,242 |
| | 1,087 |
|
| Accumulated other comprehensive income, net | — |
| | 1 |
|
| Total shareholder's equity | 3,820 |
|
| 3,577 |
|
| Total liabilities and shareholder's equity | $ | 10,642 |
|
| $ | 10,170 |
|
See the Combined Notes to Consolidated Financial Statements
230197
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholder's Equity
| | | (In millions) | Common Stock | | Retained Earnings | | Accumulated Other Comprehensive Income | | Total Shareholder's Equity | (In millions) | Common
Stock | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income | | Total
Shareholder's
Equity |
| Balance, December 31, 2015 | $ | 2,455 |
| | $ | 780 |
| | $ | 1 |
| | $ | 3,236 |
| |
| Net income | — |
| | 438 |
| | — |
| | 438 |
| |
| Common stock dividends | — |
| | (277 | ) | | — |
| | (277 | ) | |
| Contributions from parent | 18 |
| | — |
| | — |
| | 18 |
| |
| Balance, December 31, 2016 | $ | 2,473 |
|
| $ | 941 |
|
| $ | 1 |
|
| $ | 3,415 |
| |
| Net income | — |
| | 434 |
| | — |
| | 434 |
| |
| Common stock dividends | — |
| | (288 | ) | | — |
| | (288 | ) | |
| Contributions from parent | 16 |
| | — |
| | — |
| | 16 |
| |
| Balance, December 31, 2017 | $ | 2,489 |
|
| $ | 1,087 |
|
| $ | 1 |
|
| $ | 3,577 |
| Balance, December 31, 2017 | $ | 2,489 | | | $ | 1,087 | | | $ | 1 | | | $ | 3,577 | |
| Net income | — |
| | 460 |
| | — |
| | 460 |
| Net income | — | | | 460 | | | — | | | 460 | |
| Common stock dividends | — |
| | (306 | ) | | — |
| | (306 | ) | Common stock dividends | — | | | (306) | | | — | | | (306) | |
| Contributions from parent | 89 |
| | — |
| | — |
| | 89 |
| Contributions from parent | 89 | | | — | | | 0 | | | 89 | |
| Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard | — |
| | 1 |
| | (1 | ) | | — |
| Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard | — | | | 1 | | | (1) | | | 0 | |
| Balance, December 31, 2018 | $ | 2,578 |
|
| $ | 1,242 |
|
| $ | — |
|
| $ | 3,820 |
| Balance, December 31, 2018 | $ | 2,578 | | | $ | 1,242 | | | $ | 0 | | | $ | 3,820 | |
| Net income | | Net income | — | | | 528 | | | — | | | 528 | |
| Common stock dividends | | Common stock dividends | — | | | (358) | | | — | | | (358) | |
| Contributions from parent | | Contributions from parent | 188 | | | — | | | 0 | | | 188 | |
| | Balance, December 31, 2019 | | Balance, December 31, 2019 | $ | 2,766 | | | $ | 1,412 | | | $ | 0 | | | $ | 4,178 | |
| Net income | | Net income | — | | | 447 | | | — | | | 447 | |
| Common stock dividends | | Common stock dividends | — | | | (340) | | | — | | | (340) | |
| | Contributions from parent | | Contributions from parent | 248 | | | — | | | 0 | | | 248 | |
| | Balance, December 31, 2020 | | Balance, December 31, 2020 | $ | 3,014 | | | $ | 1,519 | | | $ | 0 | | | $ | 4,533 | |
See the Combined Notes to Consolidated Financial Statements
231198
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Operating revenues | | | | | |
| Electric operating revenues | $ | 2,323 | | | $ | 2,368 | | | $ | 2,428 | |
| Natural gas operating revenues | 739 | | | 700 | | | 738 | |
| Revenues from alternative revenue programs | 16 | | | 12 | | | (26) | |
| Operating revenues from affiliates | 20 | | | 26 | | | 29 | |
| Total operating revenues | 3,098 | | | 3,106 | | | 3,169 | |
| Operating expenses | | | | | |
| Purchased power | 509 | | | 585 | | | 671 | |
| Purchased fuel | 171 | | | 181 | | | 254 | |
| Purchased power and fuel from affiliates | 311 | | | 286 | | | 257 | |
| Operating and maintenance | 617 | | | 600 | | | 615 | |
| Operating and maintenance from affiliates | 172 | | | 160 | | | 162 | |
| Depreciation and amortization | 550 | | | 502 | | | 483 | |
| Taxes other than income taxes | 268 | | | 260 | | | 254 | |
| Total operating expenses | 2,598 | | | 2,574 | | | 2,696 | |
| Gain on sales of assets | 0 | | | 0 | | | 1 | |
| Operating income | 500 | | | 532 | | | 474 | |
| Other income and (deductions) | | | | | |
| Interest expense, net | (133) | | | (121) | | | (106) | |
| | | | | |
| Other, net | 23 | | | 28 | | | 19 | |
| Total other income and (deductions) | (110) | | | (93) | | | (87) | |
| Income before income taxes | 390 | | | 439 | | | 387 | |
| Income taxes | 41 | | | 79 | | | 74 | |
| Net income | $ | 349 | | | $ | 360 | | | $ | 313 | |
| | | | | |
| | | | | |
| | | | | |
| Comprehensive income | $ | 349 | | | $ | 360 | | | $ | 313 | |
| | | | | |
| | | | | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Operating revenues | | | | | |
| Electric operating revenues | $ | 2,428 |
| | $ | 2,384 |
| | $ | 2,531 |
|
| Natural gas operating revenues | 738 |
| | 652 |
| | 628 |
|
| Revenues from alternative revenue programs | (26 | ) | | 124 |
| | 53 |
|
| Operating revenues from affiliates | 29 |
| | 16 |
| | 21 |
|
| Total operating revenues | 3,169 |
|
| 3,176 |
|
| 3,233 |
|
| Operating expenses | | | | | |
| Purchased power | 671 |
| | 566 |
| | 528 |
|
| Purchased fuel | 254 |
| | 183 |
| | 162 |
|
| Purchased power from affiliates | 257 |
| | 384 |
| | 604 |
|
| Operating and maintenance | 615 |
| | 563 |
| | 605 |
|
| Operating and maintenance from affiliates | 162 |
| | 153 |
| | 132 |
|
| Depreciation and amortization | 483 |
| | 473 |
| | 423 |
|
| Taxes other than income | 254 |
| | 240 |
| | 229 |
|
| Total operating expenses | 2,696 |
|
| 2,562 |
|
| 2,683 |
|
| Gain on sales of assets | 1 |
| | — |
| | — |
|
| Operating income | 474 |
|
| 614 |
|
| 550 |
|
| Other income and (deductions) | | | | | |
| Interest expense, net | (106 | ) | | (95 | ) | | (87 | ) |
| Interest expense to affiliates | — |
| | (10 | ) | | (16 | ) |
| Other, net | 19 |
| | 16 |
| | 21 |
|
| Total other income and (deductions) | (87 | ) |
| (89 | ) |
| (82 | ) |
| Income before income taxes | 387 |
| | 525 |
| | 468 |
|
| Income taxes | 74 |
| | 218 |
| | 174 |
|
| Net income | 313 |
|
| 307 |
|
| 294 |
|
| Preference stock dividends | — |
| | — |
| | 8 |
|
| Net income attributable to common shareholder | $ | 313 |
|
| $ | 307 |
|
| $ | 286 |
|
| | | | | | |
| Comprehensive income | $ | 313 |
|
| $ | 307 |
|
| $ | 294 |
|
| Comprehensive income attributable to preference stock dividends | — |
| | — |
| | 8 |
|
| Comprehensive income attributable to common shareholder | $ | 313 |
| | $ | 307 |
| | $ | 286 |
|
See the Combined Notes to Consolidated Financial Statements
232199
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Statements of Cash Flows
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 349 | | | $ | 360 | | | $ | 313 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | |
| Depreciation and amortization | 550 | | | 502 | | | 483 | |
| | | | | |
| | | | | |
| Deferred income taxes and amortization of investment tax credits | 37 | | | 130 | | | 76 | |
| Other non-cash operating activities | 97 | | | 85 | | | 58 | |
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | (165) | | | 25 | | | 8 | |
| Receivables from and payables to affiliates, net | (8) | | | 1 | | | 12 | |
| Inventories | 10 | | | (1) | | | 2 | |
| Accounts payable and accrued expenses | 102 | | | (43) | | | (1) | |
| Collateral (posted) received, net | 0 | | | (4) | | | 4 | |
| Income taxes | 60 | | | (67) | | | (20) | |
| Pension and non-pension postretirement benefit contributions | (78) | | | (48) | | | (54) | |
| Other assets and liabilities | (70) | | | (192) | | | (92) | |
| Net cash flows provided by operating activities | 884 | | | 748 | | | 789 | |
| Cash flows from investing activities | | | | | |
| Capital expenditures | (1,247) | | | (1,145) | | | (959) | |
| | | | | |
| Other investing activities | 2 | | | 8 | | | 9 | |
| Net cash flows used in investing activities | (1,245) | | | (1,137) | | | (950) | |
| Cash flows from financing activities | | | | | |
| Changes in short-term borrowings | (76) | | | 40 | | | (42) | |
| Issuance of long-term debt | 400 | | | 400 | | | 300 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Dividends paid on common stock | (246) | | | (224) | | | (209) | |
| | | | | |
| Contributions from parent | 411 | | | 193 | | | 109 | |
| Other financing activities | (8) | | | (8) | | | (2) | |
| Net cash flows provided by financing activities | 481 | | | 401 | | | 156 | |
| Increase (decrease) in cash, restricted cash, and cash equivalents | 120 | | | 12 | | | (5) | |
| Cash, restricted cash, and cash equivalents at beginning of period | 25 | | | 13 | | | 18 | |
| Cash, restricted cash, and cash equivalents at end of period | $ | 145 | | | $ | 25 | | | $ | 13 | |
| | | | | |
| Supplemental cash flow information | | | | | |
| Increase in capital expenditures not paid | $ | 53 | | | $ | 6 | | | $ | 50 | |
| | | | | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 313 |
| | $ | 307 |
| | $ | 294 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | |
| Depreciation and amortization | 483 |
| | 473 |
| | 423 |
|
| Impairment losses on long-lived assets and regulatory assets | — |
| | 7 |
| | 52 |
|
| Deferred income taxes and amortization of investment tax credits | 76 |
| | 145 |
| | 118 |
|
| Other non-cash operating activities | 58 |
| | 65 |
| | 88 |
|
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | 8 |
| | (5 | ) | | (98 | ) |
| Receivables from and payables to affiliates, net | 12 |
| | (4 | ) | | 3 |
|
| Inventories | 2 |
| | (9 | ) | | 1 |
|
| Accounts payable and accrued expenses | (1 | ) | | (15 | ) | | 138 |
|
| Collateral received, net | 4 |
| | — |
| | — |
|
| Income taxes | (20 | ) | | 60 |
| | 18 |
|
| Pension and non-pension postretirement benefit contributions | (54 | ) | | (53 | ) | | (49 | ) |
| Other assets and liabilities | (92 | ) | | (150 | ) | | (43 | ) |
| Net cash flows provided by operating activities | 789 |
|
| 821 |
|
| 945 |
|
| Cash flows from investing activities | | | | | |
| Capital expenditures | (959 | ) | | (882 | ) | | (934 | ) |
| Other investing activities | 9 |
| | 7 |
| | 24 |
|
| Net cash flows used in investing activities | (950 | ) |
| (875 | ) |
| (910 | ) |
| Cash flows from financing activities | | | | | |
| Changes in short-term borrowings | (42 | ) | | 32 |
| | (165 | ) |
| Issuance of long-term debt | 300 |
| | 300 |
| | 850 |
|
| Retirement of long-term debt | — |
| | (41 | ) | | (379 | ) |
| Retirement of long-term debt to financing trust | — |
| | (250 | ) | | — |
|
| Redemption of preference stock | — |
| | — |
| | (190 | ) |
| Dividends paid on preference stock | — |
| | — |
| | (8 | ) |
| Dividends paid on common stock | (209 | ) | | (198 | ) | | (179 | ) |
| Contributions from parent | 109 |
| | 184 |
| | 61 |
|
| Other financing activities | (2 | ) | | (5 | ) | | (11 | ) |
| Net cash flows provided by (used in) financing activities | 156 |
|
| 22 |
|
| (21 | ) |
| (Decrease) increase in cash, cash equivalents and restricted cash | (5 | ) | | (32 | ) | | 14 |
|
| Cash, cash equivalents and restricted cash at beginning of period | 18 |
| | 50 |
| | 36 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 13 |
|
| $ | 18 |
|
| $ | 50 |
|
See the Combined Notes to Consolidated Financial Statements
233200
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Balance Sheets
| | | | | | | | | | | |
| December 31, |
| (In millions) | 2020 | | 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 144 | | | $ | 24 | |
| Restricted cash and cash equivalents | 1 | | | 1 | |
| Accounts receivable | | | |
| Customer accounts receivable | 487 | | 329 |
| Customer allowance for credit losses | (35) | | (12) |
| Customer accounts receivable, net | 452 | | | 317 | |
| Other accounts receivable | 117 | | 152 |
| Other allowance for credit losses | (9) | | (5) |
| Other accounts receivable, net | 108 | | | 147 | |
| Receivables from affiliates | 3 | | | 1 | |
| Inventories, net | | | |
| Fossil fuel | 25 | | | 30 | |
| Materials and supplies | 41 | | | 46 | |
| | | |
| Prepaid utility taxes | 0 | | | 78 | |
| Regulatory assets | 168 | | | 183 | |
| Other | 6 | | | 6 | |
| Total current assets | 948 | | | 833 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $4,034 and $3,834 as of December 31, 2020 and 2019, respectively) | 9,872 | | | 8,990 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 481 | | | 454 | |
| Investments | 10 | | | 7 | |
| | | |
| Prepaid pension asset | 270 | | | 264 | |
| Other | 69 | | | 86 | |
| Total deferred debits and other assets | 830 | | | 811 | |
| Total assets | $ | 11,650 | | | $ | 10,634 | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 |
| 2017 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 7 |
| | $ | 17 |
|
| Restricted cash and cash equivalents | 6 |
| | 1 |
|
| Accounts receivable, net | | | |
| Customer | 353 |
| | 375 |
|
| Other | 90 |
| | 94 |
|
| Receivables from affiliates | 1 |
| | 1 |
|
| Inventories, net | | | |
| Gas held in storage | 36 |
| | 37 |
|
| Materials and supplies | 39 |
| | 40 |
|
| Prepaid utility taxes | 74 |
| | 69 |
|
| Regulatory assets | 177 |
| | 174 |
|
| Other | 3 |
| | 3 |
|
| Total current assets | 786 |
|
| 811 |
|
| Property, plant and equipment, net | 8,243 |
| | 7,602 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 398 |
| | 397 |
|
| Investments | 5 |
| | 5 |
|
| Prepaid pension asset | 279 |
| | 285 |
|
| Other | 5 |
| | 4 |
|
| Total deferred debits and other assets | 687 |
|
| 691 |
|
| Total assets | $ | 9,716 |
|
| $ | 9,104 |
|
See the Combined Notes to Consolidated Financial Statements
234201
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Balance Sheets
| | | | | | | | | | | |
| December 31, |
| (In millions) | 2020 | | 2019 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 0 | | | $ | 76 | |
| Long-term debt due within one year | 300 | | | 0 | |
| Accounts payable | 346 | | | 243 | |
| Accrued expenses | 205 | | | 152 | |
| | | |
| Payables to affiliates | 61 | | | 66 | |
| Customer deposits | 110 | | | 120 | |
| Regulatory liabilities | 30 | | | 33 | |
| Other | 91 | | | 63 | |
| Total current liabilities | 1,143 | | | 753 | |
| Long-term debt | 3,364 | | | 3,270 | |
| | | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 1,521 | | | 1,396 | |
| Asset retirement obligations | 23 | | | 22 | |
| Non-pension postretirement benefits obligations | 189 | | | 199 | |
| Regulatory liabilities | 1,109 | | | 1,195 | |
| Other | 104 | | | 116 | |
| Total deferred credits and other liabilities | 2,946 | | | 2,928 | |
| Total liabilities | 7,453 | | | 6,951 | |
| Commitments and contingencies | 0 | | 0 |
| Shareholder's equity | | | |
Common stock (NaN par value, 0 shares(a) authorized, 0 shares(a) outstanding at December 31, 2020 and 2019) | 2,318 | | | 1,907 | |
| Retained earnings | 1,879 | | | 1,776 | |
| | | |
| Total shareholder's equity | 4,197 | | | 3,683 | |
| | | |
| | | |
| Total liabilities and shareholder's equity | $ | 11,650 | | | $ | 10,634 | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 35 |
| | $ | 77 |
|
| Accounts payable | 295 |
| | 265 |
|
| Accrued expenses | 155 |
| | 164 |
|
| Payables to affiliates | 65 |
| | 52 |
|
| Customer deposits | 120 |
| | 116 |
|
| Regulatory liabilities | 77 |
| | 62 |
|
| Other | 27 |
| | 24 |
|
| Total current liabilities | 774 |
|
| 760 |
|
| Long-term debt | 2,876 |
| | 2,577 |
|
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 1,222 |
| | 1,244 |
|
| Asset retirement obligations | 24 |
| | 23 |
|
| Non-pension postretirement benefits obligations | 201 |
| | 202 |
|
| Regulatory liabilities | 1,192 |
| | 1,101 |
|
| Other | 73 |
| | 56 |
|
| Total deferred credits and other liabilities | 2,712 |
|
| 2,626 |
|
| Total liabilities | 6,362 |
|
| 5,963 |
|
| Commitments and contingencies |
| |
|
| Shareholder's equity | | | |
| Common stock | 1,714 |
| | 1,605 |
|
| Retained earnings | 1,640 |
| | 1,536 |
|
| Total shareholder's equity | 3,354 |
|
| 3,141 |
|
| Total liabilities and shareholder's equity | $ | 9,716 |
|
| $ | 9,104 |
|
(a)In millions, shares round to zero. Number of shares is 1,500 authorized and 1,000 outstanding at December 31, 2020 and 2019.
See the Combined Notes to Consolidated Financial Statements
235202
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholder's Equity
| | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Common
Stock | | Retained
Earnings | | | | Total
Shareholder's
Equity | | | | |
| Balance, December 31, 2017 | $ | 1,605 | | | $ | 1,536 | | | | | $ | 3,141 | | | | | |
| Net income | — | | | 313 | | | | | 313 | | | | | |
| | | | | | | | | | | |
| Common stock dividends | — | | | (209) | | | | | (209) | | | | | |
| | | | | | | | | | | |
| Contributions from parent | 109 | | | 0 | | | | | 109 | | | | | |
| | | | | | | | | | | |
| Balance, December 31, 2018 | $ | 1,714 | | | $ | 1,640 | | | | | $ | 3,354 | | | | | |
| Net income | — | | | 360 | | | | | 360 | | | | | |
| | | | | | | | | | | |
| Common stock dividends | — | | | (224) | | | | | (224) | | | | | |
| | | | | | | | | | | |
| Contributions from parent | 193 | | | 0 | | | | | 193 | | | | | |
| | | | | | | | | | | |
| Balance, December 31, 2019 | $ | 1,907 | | | $ | 1,776 | | | | | $ | 3,683 | | | | | |
| Net income | — | | | 349 | | | | | 349 | | | | | |
| Common stock dividends | — | | | (246) | | | | | (246) | | | | | |
| | | | | | | | | | | |
| Contributions from parent | 411 | | | 0 | | | | | 411 | | | | | |
| | | | | | | | | | | |
| Balance, December 31, 2020 | $ | 2,318 | | | $ | 1,879 | | | | | $ | 4,197 | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity | | Preference stock not subject to mandatory redemption | | Total Equity |
| Balance, December 31, 2015 | $ | 1,367 |
| | $ | 1,320 |
| | $ | 2,687 |
| | $ | 190 |
| | $ | 2,877 |
|
| Net income | — |
| | 294 |
| | 294 |
| | — |
| | 294 |
|
| Preference stock dividends | — |
| | (8 | ) | | (8 | ) | | — |
| | (8 | ) |
| Common stock dividends | — |
| | (179 | ) | | (179 | ) | | — |
| | (179 | ) |
| Distributions to parent | (7 | ) | | — |
| | (7 | ) | |
|
| | (7 | ) |
| Contributions from parent | 61 |
| | — |
| | 61 |
| | — |
| | 61 |
|
| Redemption of preference stock | — |
| | — |
| | — |
| | (190 | ) | | (190 | ) |
| Balance, December 31, 2016 | $ | 1,421 |
|
| $ | 1,427 |
|
| $ | 2,848 |
|
| $ | — |
|
| $ | 2,848 |
|
| Net income | — |
| | 307 |
| | 307 |
| | — |
| | 307 |
|
| Common stock dividends | — |
| | (198 | ) | | (198 | ) | | — |
| | (198 | ) |
| Contributions from parent | 184 |
| | — |
| | 184 |
| | — |
| | 184 |
|
| Balance, December 31, 2017 | $ | 1,605 |
|
| $ | 1,536 |
|
| $ | 3,141 |
|
| $ | — |
|
| $ | 3,141 |
|
| Net income | — |
| | 313 |
| | 313 |
| | — |
| | 313 |
|
| Common stock dividends | — |
| | (209 | ) | | (209 | ) | | — |
| | (209 | ) |
| Contributions from parent | 109 |
| | — |
| | 109 |
| | — |
| | 109 |
|
| Balance, December 31, 2018 | $ | 1,714 |
|
| $ | 1,640 |
|
| $ | 3,354 |
|
| $ | — |
|
| $ | 3,354 |
|
See the Combined Notes to Consolidated Financial Statements
236203
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income (Loss)
| | | | | | | | | | | | | | | | | | | | |
| | | | |
| For the Years Ended December 31, | | | |
| (In millions) | 2020 | | 2019 | | 2018 | | | |
| Operating revenues | | | | | | | | |
| Electric operating revenues | $ | 4,463 | | | $ | 4,639 | | | $ | 4,609 | | | | |
| Natural gas operating revenues | 162 | | | 167 | | | 181 | | | | |
| Revenues from alternative revenue programs | 21 | | | (14) | | | (7) | | | | |
| Operating revenues from affiliates | 17 | | | 14 | | | 15 | | | | |
| Total operating revenues | 4,663 | | | 4,806 | | | 4,798 | | | | |
| Operating expenses | | | | | | | | |
| Purchased power | 1,279 | | | 1,371 | | | 1,387 | | | | |
| Purchased fuel | 69 | | | 75 | | | 89 | | | | |
| Purchased power from affiliates | 366 | | | 352 | | | 355 | | | | |
| Operating and maintenance | 940 | | | 939 | | | 978 | | | | |
| Operating and maintenance from affiliates | 159 | | | 143 | | | 152 | | | | |
| Depreciation and amortization | 782 | | | 754 | | | 740 | | | | |
| Taxes other than income taxes | 450 | | | 450 | | | 455 | | | | |
| | | | | | | | |
| Total operating expenses | 4,045 | | | 4,084 | | | 4,156 | | | | |
| | | | | | | | |
| Gain on sales of assets | 11 | | | 0 | | | 1 | | | | |
| Operating income | 629 | | | 722 | | | 643 | | | | |
| Other income and (deductions) | | | | | | | | |
| Interest expense, net | (268) | | | (263) | | | (261) | | | | |
| | | | | | | | |
| Other, net | 57 | | | 55 | | | 43 | | | | |
| Total other income and (deductions) | (211) | | | (208) | | | (218) | | | | |
| Income before income taxes | 418 | | | 514 | | | 425 | | | | |
| Income taxes | (77) | | | 38 | | | 33 | | | | |
| Equity in earnings of unconsolidated affiliate | 0 | | | 1 | | | 1 | | | | |
| Net income | $ | 495 | | | $ | 477 | | | $ | 393 | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Comprehensive income | $ | 495 | | | $ | 477 | | | $ | 393 | | | | |
|
| | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the Years Ended
December 31, | | March 24 to December 31, | | | January 1 to March 23, |
| (In millions) | 2018 | | 2017 | | 2016 | | | 2016 |
| Operating revenues | | | | | | | | |
| Electric operating revenues | $ | 4,609 |
| | $ | 4,428 |
| | $ | 3,463 |
| | | $ | 1,122 |
|
| Natural gas operating revenues | 181 |
| | 161 |
| | 92 |
| | | 57 |
|
| Revenues from alternative revenue programs | — |
| | 40 |
| | 43 |
| | | (26 | ) |
| Operating revenues from affiliates | 15 |
| | 50 |
| | 45 |
| | | — |
|
| Total operating revenues | 4,805 |
|
| 4,679 |
| | 3,643 |
| | | 1,153 |
|
| Operating expenses | | | | | | | | |
| Purchased power | 1,387 |
| | 1,182 |
| | 925 |
| | | 471 |
|
| Purchased fuel | 89 |
| | 71 |
| | 36 |
| | | 26 |
|
| Purchased power from affiliates | 355 |
| | 463 |
| | 486 |
| | | — |
|
| Operating and maintenance | 978 |
| | 918 |
| | 1,144 |
| | | 294 |
|
| Operating and maintenance from affiliates | 152 |
| | 150 |
| | 89 |
| | | — |
|
| Depreciation, amortization and accretion | 740 |
| | 675 |
| | 515 |
| | | 152 |
|
| Taxes other than income | 455 |
| | 452 |
| | 354 |
| | | 105 |
|
| Total operating expenses | 4,156 |
|
| 3,911 |
| | 3,549 |
| | | 1,048 |
|
| Gain (loss) on sales of assets | 1 |
| | 1 |
| | (1 | ) | | | — |
|
| Operating income | 650 |
|
| 769 |
| | 93 |
| | | 105 |
|
| Other income and (deductions) | | | | | | | | |
| Interest expense, net | (261 | ) | | (245 | ) | | (195 | ) | | | (65 | ) |
| Other, net | 43 |
| | 54 |
| | 44 |
| | | (4 | ) |
| Total other income and (deductions) | (218 | ) | | (191 | ) | | (151 | ) | | | (69 | ) |
| Income (loss) before income taxes | 432 |
|
| 578 |
| | (58 | ) | | | 36 |
|
| Income taxes | 35 |
| | 217 |
| | 3 |
| | | 17 |
|
| Equity in earnings of unconsolidated affiliates | 1 |
| | 1 |
| | — |
| | | — |
|
| Net income (loss) | 398 |
| | 362 |
| | (61 | ) | | | 19 |
|
| Net income (loss) attributable to membership interest/common shareholders | $ | 398 |
| | $ | 362 |
| | $ | (61 | ) | | | $ | 19 |
|
| Comprehensive income (loss), net of income taxes | | | | | | | | |
| Net income (loss) | $ | 398 |
| | $ | 362 |
| | $ | (61 | ) | | | $ | 19 |
|
| Other comprehensive income (loss), net of income taxes | | | | | | | | |
| Pension and non-pension postretirement benefit plans: | | | | | | | | |
| Actuarial loss reclassified to periodic cost | — |
| | — |
| | — |
| | | 1 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | | 1 |
|
| Comprehensive income (loss) | $ | 398 |
| | $ | 362 |
| | $ | (61 | ) | | | $ | 20 |
|
See the Combined Notes to Consolidated Financial Statements
237204
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
| | | | | | | | | | | | | | | | | |
| For the Years Ended
December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 495 | | | $ | 477 | | | $ | 393 | |
| | | | | |
| Adjustments to reconcile net income to net cash from operating activities: | | | | | |
| Depreciation and amortization | 782 | | | 754 | | | 740 | |
| | | | | |
| | | | | |
| Deferred income taxes and amortization of investment tax credits | (97) | | | (7) | | | 30 | |
| | | | | |
| Other non-cash operating activities | 103 | | | 161 | | | 150 | |
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | (159) | | | (39) | | | (2) | |
| Receivables from and payables to affiliates, net | 3 | | | 3 | | | 8 | |
| Inventories | (6) | | | (27) | | | (14) | |
| Accounts payable and accrued expenses | 49 | | | (17) | | | 45 | |
| | | | | |
| | | | | |
| Income taxes | (25) | | | 16 | | | 34 | |
| Pension and non-pension postretirement benefit contributions | (39) | | | (25) | | | (74) | |
| Other assets and liabilities | (104) | | | (179) | | | (178) | |
| Net cash flows provided by operating activities | 1,002 | | | 1,117 | | | 1,132 | |
| Cash flows from investing activities | | | | | |
| Capital expenditures | (1,604) | | | (1,355) | | | (1,375) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Other investing activities | 7 | | | (3) | | | 4 | |
| Net cash flows used in investing activities | (1,597) | | | (1,358) | | | (1,371) | |
| Cash flows from financing activities | | | | | |
| Changes in short-term borrowings | 160 | | | 154 | | | (296) | |
| Proceeds from short-term borrowings with maturities greater than 90 days | 0 | | | 0 | | | 125 | |
| Repayments of short-term borrowings with maturities greater than 90 days | 0 | | | (125) | | | 0 | |
| Issuance of long-term debt | 602 | | | 485 | | | 750 | |
| Retirement of long-term debt | (128) | | | (157) | | | (299) | |
| Change in Exelon intercompany money pool | 9 | | | 12 | | | 0 | |
| | | | | |
| | | | | |
| | | | | |
| Distributions to member | (553) | | | (526) | | | (326) | |
| Contributions from member | 494 | | | 398 | | | 385 | |
| | | | | |
| | | | | |
| | | | | |
| Other financing activities | (10) | | | (5) | | | (9) | |
| Net cash flows provided by financing activities | 574 | | | 236 | | | 330 | |
| (Decrease) increase in cash, restricted cash, and cash equivalents | (21) | | | (5) | | | 91 | |
| Cash, restricted cash, and cash equivalents at beginning of period | 181 | | | 186 | | | 95 | |
| Cash, restricted cash, and cash equivalents at end of period | $ | 160 | | | $ | 181 | | | $ | 186 | |
| | | | | |
| Supplemental cash flow information | | | | | |
| Increase in capital expenditures not paid | $ | 54 | | | $ | 2 | | | $ | 93 | |
| | | | | |
|
| | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the Years Ended December 31, | | March 24 to December 31, | | | January 1 to March 23, |
| (In millions) | 2018 | | 2017 | | 2016 | | | 2016 |
| Cash flows from operating activities | | | | | | | | |
| Net income (loss) | $ | 398 |
| | $ | 362 |
| | $ | (61 | ) | | | $ | 19 |
|
| Adjustments to reconcile net income (loss) to net cash from operating activities: | | | | | | | | |
| Depreciation and amortization | 740 |
| | 675 |
| | 515 |
| | | 152 |
|
| Impairment losses on intangibles and regulatory assets | — |
| | 52 |
| | — |
| | | — |
|
| Deferred income taxes and amortization of investment tax credits | 32 |
| | 252 |
| | 295 |
| | | 19 |
|
| Net fair value changes related to derivatives | — |
| | — |
| | — |
| | | 18 |
|
| Other non-cash operating activities | 143 |
| | 58 |
| | 515 |
| | | 46 |
|
| Changes in assets and liabilities: | | | | | | | | |
| Accounts receivable | (2 | ) | | (26 | ) | | (21 | ) | | | (28 | ) |
| Receivables from and payables to affiliates, net | 8 |
| | (2 | ) | | 42 |
| | | — |
|
| Inventories | (14 | ) | | (37 | ) | | 3 |
| | | (4 | ) |
| Accounts payable and accrued expenses | 45 |
| | (106 | ) | | 19 |
| | | 42 |
|
| Income taxes | 34 |
| | 79 |
| | (22 | ) | | | 12 |
|
| Pension and non-pension postretirement benefit contributions | (74 | ) | | (99 | ) | | (86 | ) | | | (4 | ) |
| Other assets and liabilities | (178 | ) | | (258 | ) | | (311 | ) | | | (8 | ) |
| Net cash flows provided by operating activities | 1,132 |
| | 950 |
| | 888 |
| | | 264 |
|
| Cash flows from investing activities | | | | | | | | |
| Capital expenditures | (1,375 | ) | | (1,396 | ) | | (1,008 | ) | | | (273 | ) |
| Purchases of investments | — |
| | — |
| | — |
| | | (68 | ) |
| Other investing activities | 4 |
| | (1 | ) | | 15 |
| | | (5 | ) |
| Net cash flows used in investing activities | (1,371 | ) | | (1,397 | ) | | (993 | ) | | | (346 | ) |
| Cash flows from financing activities | | | | | | | | |
| Changes in short-term borrowings | (296 | ) | | 328 |
| | (515 | ) | | | (121 | ) |
| Proceeds from short-term borrowings with maturities greater than 90 days | 125 |
| | — |
| | — |
| | | 500 |
|
| Repayments of short-term borrowings with maturities greater than 90 days | — |
| | (500 | ) | | (300 | ) | | | — |
|
| Issuance of long-term debt | 750 |
| | 202 |
| | 179 |
| | | — |
|
| Retirement of long-term debt | (299 | ) | | (169 | ) | | (338 | ) | | | (11 | ) |
| Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation | — |
| | — |
| | — |
| | | 2 |
|
| Distributions to member | (326 | ) | | (311 | ) | | (273 | ) | | | — |
|
| Contributions from member | 385 |
| | 758 |
| | 1,251 |
| | | — |
|
| Change in Exelon intercompany money pool | — |
| | — |
| | (6 | ) | | | — |
|
| Other financing activities | (9 | ) | | (2 | ) | | (5 | ) | | | 2 |
|
| Net cash flows provided by (used in) financing activities | 330 |
| | 306 |
| | (7 | ) | | | 372 |
|
| Increase (decrease) in cash, cash equivalents and restricted cash | 91 |
| | (141 | ) |
| (112 | ) | |
| 290 |
|
| Cash, cash equivalents and restricted cash at beginning of period | 95 |
| | 236 |
| | 348 |
| | | 58 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 186 |
| | $ | 95 |
|
| $ | 236 |
| |
| $ | 348 |
|
See the Combined Notes to Consolidated Financial Statements
238205
Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
| | | | | | | | | | | |
| December 31, |
| (In millions) | 2020 | | 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 111 | | | $ | 131 | |
| Restricted cash and cash equivalents | 39 | | | 36 | |
| Accounts receivable | | | |
| Customer accounts receivable | 611 | | 516 |
| Customer allowance for credit losses | (86) | | (37) |
| Customer accounts receivable, net | 525 | | | 479 | |
| Other accounts receivable | 260 | | 190 |
| Other allowance for credit losses | (33) | | (16) |
| Other accounts receivable, net | 227 | | | 174 | |
| | | |
| Receivable from affiliates | 8 | | | 1 | |
| | | |
| | | |
| Inventories, net | | | |
| Fossil fuel | 6 | | | 8 | |
| Materials and supplies | 198 | | | 190 | |
| | | |
| | | |
| Regulatory assets | 440 | | | 412 | |
| | | |
| Other | 45 | | | 49 | |
| Total current assets | 1,599 | | | 1,480 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $1,811 and $1,213 as of December 31, 2020 and 2019, respectively) | 15,377 | | | 14,296 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 1,933 | | | 2,061 | |
| Investments | 140 | | | 135 | |
| Goodwill | 4,005 | | | 4,005 | |
| | | |
| | | |
| Prepaid pension asset | 365 | | | 406 | |
| | | |
| Deferred income taxes | 10 | | | 13 | |
| Other | 307 | | | 323 | |
| Total deferred debits and other assets | 6,760 | | | 6,943 | |
Total assets(a) | $ | 23,736 | | | $ | 22,719 | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 124 |
| | $ | 30 |
|
| Restricted cash and cash equivalents | 43 |
| | 42 |
|
| Accounts receivable, net | | | |
| Customer | 453 |
| | 486 |
|
| Other | 177 |
| | 206 |
|
| Inventories, net | | | |
| Gas held in storage | 9 |
| | 7 |
|
| Materials and supplies | 163 |
| | 151 |
|
| Regulatory assets | 489 |
| | 554 |
|
| Other | 75 |
| | 75 |
|
| Total current assets | 1,533 |
| | 1,551 |
|
| Property, plant and equipment, net | 13,446 |
| | 12,498 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 2,312 |
| | 2,493 |
|
| Investments | 130 |
| | 132 |
|
| Goodwill | 4,005 |
| | 4,005 |
|
| Long-term note receivable | — |
| | 4 |
|
| Prepaid pension asset | 486 |
| | 490 |
|
| Deferred income taxes | 12 |
| | 4 |
|
| Other | 60 |
| | 70 |
|
| Total deferred debits and other assets | 7,005 |
| | 7,198 |
|
Total assets(a) | $ | 21,984 |
| | $ | 21,247 |
|
See the Combined Notes to Consolidated Financial Statements
239206
Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
| | | | December 31, | | December 31, |
| (In millions) | 2018 | | 2017 | (In millions) | 2020 | | 2019 |
| LIABILITIES AND EQUITY | | | | LIABILITIES AND EQUITY | | | |
| Current liabilities | | | | Current liabilities | |
| Short-term borrowings | $ | 179 |
| | $ | 350 |
| Short-term borrowings | $ | 368 | | | $ | 208 | |
| Long-term debt due within one year | 125 |
| | 396 |
| Long-term debt due within one year | 347 | | | 103 | |
| Accounts payable | 496 |
| | 348 |
| Accounts payable | 539 | | | 462 | |
| Accrued expenses | 256 |
| | 261 |
| Accrued expenses | 299 | | | 296 | |
| Payables to affiliates | 94 |
| | 90 |
| Payables to affiliates | 104 | | | 98 | |
| Borrowings from Exelon intercompany money pool | | Borrowings from Exelon intercompany money pool | 21 | | | 12 | |
| Customer deposits | | Customer deposits | 106 | | | 117 | |
| Regulatory liabilities | 84 |
| | 56 |
| Regulatory liabilities | 137 | | | 70 | |
| | Unamortized energy contract liabilities | 119 |
| | 188 |
| Unamortized energy contract liabilities | 92 | | | 115 | |
| Customer deposits | 116 |
| | 119 |
| |
| | Other | 123 |
| | 123 |
| Other | 141 | | | 131 | |
| Total current liabilities | 1,592 |
| | 1,931 |
| Total current liabilities | 2,154 | | | 1,612 | |
| Long-term debt | 6,134 |
| | 5,478 |
| Long-term debt | 6,659 | | | 6,460 | |
| Deferred credits and other liabilities | | | | Deferred credits and other liabilities | |
| Deferred income taxes and unamortized investment tax credits | 2,146 |
| | 2,070 |
| Deferred income taxes and unamortized investment tax credits | 2,439 | | | 2,278 | |
| Asset retirement obligations | 52 |
| | 16 |
| Asset retirement obligations | 59 | | | 57 | |
| Non-pension postretirement benefit obligations | 103 |
| | 105 |
| Non-pension postretirement benefit obligations | 86 | | | 93 | |
| Regulatory liabilities | 1,864 |
| | 1,872 |
| Regulatory liabilities | 1,438 | | | 1,707 | |
| | Unamortized energy contract liabilities | 442 |
| | 561 |
| Unamortized energy contract liabilities | 235 | | | 327 | |
| Other | 369 |
| | 389 |
| Other | 622 | | | 577 | |
| Total deferred credits and other liabilities | 4,976 |
| | 5,013 |
| Total deferred credits and other liabilities | 4,879 | | | 5,039 | |
Total liabilities(a) | 12,702 |
| | 12,422 |
| Total liabilities(a) | 13,692 | | | 13,111 | |
| Commitments and contingencies |
| |
| Commitments and contingencies | 0 | | 0 |
| | Member's equity | | | | Member's equity | |
| Membership interest | 9,220 |
| | 8,835 |
| Membership interest | 10,112 | | | 9,618 | |
| Undistributed gains (losses) | 62 |
| | (10 | ) | |
| | Undistributed (losses) gains | | Undistributed (losses) gains | (68) | | | (10) | |
| | Total member's equity | 9,282 |
| | 8,825 |
| Total member's equity | 10,044 | | | 9,608 | |
| Total liabilities and member's equity | $ | 21,984 |
| | $ | 21,247 |
| Total liabilities and member's equity | $ | 23,736 | | | $ | 22,719 | |
_____________
| |
(a) | PHI’s consolidated total assets include $33 million and $41 million at December 31, 2018 and 2017, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $69 million and $102 million at December 31, 2018 and 2017, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 - Variable Interest Entities for additional information. |
(a)PHI’s consolidated total assets include $18 million and $20 million at December 31, 2020 and 2019, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $26 million and $44 million at December 31, 2020 and 2019, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 23 - Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
240207
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
| | | | | | | | | | | | | | | | | | | |
| (In millions) | Membership Interest | | Undistributed (Losses)/Gains | | | | Total
Member's Equity |
| Balance, December 31, 2017 | $ | 8,835 | | | $ | (28) | | | | | $ | 8,807 | |
| Net income | — | | | 393 | | | | | 393 | |
| Distribution to member | — | | | (326) | | | | | (326) | |
| Contributions from member | 385 | | | — | | | | | 385 | |
| Balance, December 31, 2018 | $ | 9,220 | | | $ | 39 | | | | | $ | 9,259 | |
| Net Income | — | | | 477 | | | | | 477 | |
| Distribution to member | — | | | (526) | | | | | (526) | |
| Contributions from member | 398 | | | — | | | | | 398 | |
| Balance, December 31, 2019 | $ | 9,618 | | | $ | (10) | | | | | $ | 9,608 | |
| Net income | — | | | 495 | | | | | 495 | |
| Distribution to member | — | | | (553) | | | | | (553) | |
| Contributions from member | 494 | | | — | | | | | 494 | |
| Balance, December 31, 2020 | $ | 10,112 | | | $ | (68) | | | | | $ | 10,044 | |
|
| | | | | | | | | | | | | | | |
| (In millions, except share data) | Common Stock(a) | | Retained Earnings | | Accumulated Other Comprehensive Loss, net | | Total Shareholders' Equity |
| Predecessor | | | | | | | |
| Balance, December 31, 2015 | $ | 3,832 |
| | $ | 617 |
| | $ | (36 | ) | | $ | 4,413 |
|
| Net income | — |
| | 19 |
| | — |
| | 19 |
|
| Original issue shares, net | 3 |
| | — |
| | — |
| | 3 |
|
| Net activity related to stock-based awards | 3 |
| | — |
| | — |
| | 3 |
|
| Other comprehensive income, net of income taxes | — |
| | — |
| | 1 |
| | 1 |
|
| Balance, March 23, 2016 | $ | 3,838 |
|
| $ | 636 |
|
| $ | (35 | ) |
| $ | 4,439 |
|
| | | | | | | | |
| Successor | Membership Interest | | Undistributed Gains/(Losses) | | Accumulated Other Comprehensive Loss, net | | Total Member's Equity |
Balance, March 24, 2016(b) | $ | 7,200 |
| | $ | — |
| | $ | — |
| | $ | 7,200 |
|
| Net loss | — |
| | (61 | ) | | — |
| | (61 | ) |
Distributions to member(c) | (400 | ) | | — |
| | — |
| | (400 | ) |
| Contributions from member | 1,251 |
| | — |
| | — |
| | 1,251 |
|
| Measurement period adjustment of Exelon’s deferred tax liabilities to reflect unitary state income tax consequences of the merger | 35 |
| | — |
| | — |
| | 35 |
|
| Distribution of net retirement benefit obligation to member | 53 |
| | — |
| | — |
| | 53 |
|
Assumption of member liabilities(d) | (62 | ) | | — |
| | — |
| | (62 | ) |
| Balance, December 31, 2016 | $ | 8,077 |
|
| $ | (61 | ) |
| $ | — |
|
| $ | 8,016 |
|
| Net Income | — |
| | 362 |
| | — |
| | 362 |
|
| Distributions to member | — |
| | (311 | ) | | — |
| | (311 | ) |
| Contributions from member | 758 |
| | — |
| | — |
| | 758 |
|
| Balance, December 31, 2017 | $ | 8,835 |
|
| $ | (10 | ) |
| $ | — |
|
| $ | 8,825 |
|
| Net Income | — |
| | 398 |
| | — |
| | 398 |
|
| Distributions to member | — |
| | (326 | ) | | — |
| | (326 | ) |
| Contributions from member | 385 |
| | — |
| | — |
| | 385 |
|
| Balance, December 31, 2018 | $ | 9,220 |
|
| $ | 62 |
|
| $ | — |
|
| $ | 9,282 |
|
__________
| |
(a) | At March 23, 2016 and December 31, 2015, PHI's (predecessor) shareholders' equity included $3,835 million and $3,829 million of other paid-in capital, and $3 million and $3 million of common stock, respectively. |
| |
(b) | The March 24, 2016, beginning balance differs from the PHI Merger total purchase price by $59 million related to an acquisition accounting adjustment recorded at Exelon Corporate to reflect unitary state income tax consequences of the merger. |
| |
(c) | Distribution to member includes $235 million of net assets associated with PHI's unregulated business interests and $165 million of cash, each of which were distributed by PHI to Exelon. |
| |
(d) | The liabilities assumed include $29 million for PHI stock-based compensation awards and $33 million for a merger related obligation, each assumed by PHI from Exelon. See Note 5 — Mergers, Acquisitions and Dispositions. |
See the Combined Notes to Consolidated Financial Statements
241208
Potomac Electric Power Company
Statements of Operations and Comprehensive Income
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Operating revenues | | | | | |
| Electric operating revenues | $ | 2,102 | | | $ | 2,258 | | | $ | 2,233 | |
| Revenues from alternative revenue programs | 40 | | | (3) | | | (7) | |
| Operating revenues from affiliates | 7 | | | 5 | | | 6 | |
| Total operating revenues | 2,149 | | | 2,260 | | | 2,232 | |
| Operating expenses | | | | | |
| Purchased power | 324 | | | 401 | | | 448 | |
| Purchased power from affiliate | 278 | | | 264 | | | 206 | |
| Operating and maintenance | 248 | | | 273 | | | 275 | |
| Operating and maintenance from affiliates | 205 | | | 209 | | | 226 | |
| Depreciation and amortization | 377 | | | 374 | | | 385 | |
| Taxes other than income taxes | 367 | | | 378 | | | 379 | |
| Total operating expenses | 1,799 | | | 1,899 | | | 1,919 | |
| | | | | |
| Gain on sales of assets | 9 | | | 0 | | | 0 | |
| | | | | |
| Operating income | 359 | | | 361 | | | 313 | |
| Other income and (deductions) | | | | | |
| Interest expense, net | (138) | | | (133) | | | (128) | |
| | | | | |
| Other, net | 38 | | | 31 | | | 31 | |
| Total other income and (deductions) | (100) | | | (102) | | | (97) | |
| Income before income taxes | 259 | | | 259 | | | 216 | |
| Income taxes | (7) | | | 16 | | | 11 | |
| | | | | |
| Net income | $ | 266 | | | $ | 243 | | | $ | 205 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Comprehensive income | $ | 266 | | | $ | 243 | | | $ | 205 | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Operating revenues | | | | | |
| Electric operating revenues | $ | 2,233 |
| | $ | 2,126 |
| | $ | 2,167 |
|
| Revenues from alternative revenue programs | — |
| | 26 |
| | 14 |
|
| Operating revenues from affiliates | 6 |
| | 6 |
| | 5 |
|
| Total operating revenues | 2,239 |
| | 2,158 |
| | 2,186 |
|
| Operating expenses | | | | | |
| Purchased power | 448 |
| | 359 |
| | 411 |
|
| Purchased power from affiliates | 206 |
| | 255 |
| | 295 |
|
| Operating and maintenance | 275 |
| | 396 |
| | 607 |
|
| Operating and maintenance from affiliates | 226 |
| | 58 |
| | 35 |
|
| Depreciation and amortization | 385 |
| | 321 |
| | 295 |
|
| Taxes other than income | 379 |
| | 371 |
| | 377 |
|
| Total operating expenses | 1,919 |
| | 1,760 |
| | 2,020 |
|
| Gain on sales of assets | — |
| | 1 |
| | 8 |
|
| Operating income | 320 |
| | 399 |
| | 174 |
|
| Other income and (deductions) | | | | | |
| Interest expense, net | (128 | ) | | (121 | ) | | (127 | ) |
| Other, net | 31 |
| | 32 |
| | 36 |
|
| Total other income and (deductions) | (97 | ) | | (89 | ) | | (91 | ) |
| Income before income taxes | 223 |
| | 310 |
| | 83 |
|
| Income taxes | 13 |
| | 105 |
| | 41 |
|
| Net income | $ | 210 |
| | $ | 205 |
| | $ | 42 |
|
| Comprehensive income | $ | 210 |
| | $ | 205 |
| | $ | 42 |
|
See the Combined Notes to Consolidated Financial Statements
242209
Potomac Electric Power Company
Statements of Cash Flows
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 266 | | | $ | 243 | | | $ | 205 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | |
| Depreciation and amortization | 377 | | | 374 | | | 385 | |
| | | | | |
| | | | | |
| Deferred income taxes and amortization of investment tax credits | (46) | | | 1 | | | (20) | |
| Other non-cash operating activities | (23) | | | 56 | | | 67 | |
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | (67) | | | (22) | | | (5) | |
| Receivables from and payables to affiliates, net | (12) | | | 5 | | | (17) | |
| Inventories | 1 | | | (19) | | | (6) | |
| Accounts payable and accrued expenses | 41 | | | (39) | | | 59 | |
| Income taxes | (1) | | | 9 | | | (13) | |
| Pension and non-pension postretirement benefit contributions | (11) | | | (14) | | | (17) | |
| Other assets and liabilities | (24) | | | (82) | | | (164) | |
| Net cash flows provided by operating activities | 501 | | | 512 | | | 474 | |
| Cash flows from investing activities | | | | | |
| Capital expenditures | (773) | | | (626) | | | (656) | |
| | | | | |
| | | | | |
| | | | | |
| Other investing activities | 0 | | | 3 | | | 2 | |
| Net cash flows used in investing activities | (773) | | | (623) | | | (654) | |
| Cash flows from financing activities | | | | | |
| Changes in short-term borrowings | (47) | | | 42 | | | 14 | |
| Issuance of long-term debt | 300 | | | 260 | | | 200 | |
| Retirement of long-term debt | (3) | | | (125) | | | (14) | |
| Dividends paid on common stock | (232) | | | (213) | | | (169) | |
| Contributions from parent | 262 | | | 160 | | | 166 | |
| Other financing activities | (6) | | | (3) | | | (4) | |
| Net cash flows provided by financing activities | 274 | | | 121 | | | 193 | |
| Increase in cash, restricted cash, and cash equivalents | 2 | | | 10 | | | 13 | |
| Cash, restricted cash, and cash equivalents at beginning of period | 63 | | | 53 | | | 40 | |
| Cash, restricted cash, and cash equivalents at end of period | $ | 65 | | | $ | 63 | | | $ | 53 | |
| | | | | |
| Supplemental cash flow information | | | | | |
| Increase in capital expenditures not paid | $ | 1 | | | $ | 39 | | | $ | 20 | |
| | | | | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 210 |
| | $ | 205 |
| | $ | 42 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | |
| Depreciation and amortization | 385 |
| | 321 |
| | 295 |
|
| Impairment losses on regulatory assets | — |
| | 14 |
| | — |
|
| Deferred income taxes and amortization of investment tax credits | (18 | ) | | 113 |
| | 153 |
|
| Other non-cash operating activities | 60 |
| | (6 | ) | | 175 |
|
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | (5 | ) | | (20 | ) | | (41 | ) |
| Receivables from and payables to affiliates, net | (17 | ) | | — |
| | 44 |
|
| Inventories | (6 | ) | | (24 | ) | | 1 |
|
| Accounts payable and accrued expenses | 59 |
| | (63 | ) | | 32 |
|
| Income taxes | (13 | ) | | 81 |
| | 110 |
|
| Pension and non-pension postretirement benefit contributions | (17 | ) | | (72 | ) | | (32 | ) |
| Other assets and liabilities | (164 | ) | | (142 | ) | | (128 | ) |
| Net cash flows provided by operating activities | 474 |
| | 407 |
| | 651 |
|
| Cash flows from investing activities | | | | | |
| Capital expenditures | (656 | ) | | (628 | ) | | (586 | ) |
| Purchases of investments | — |
| | — |
| | (30 | ) |
| Other investing activities | 2 |
| | — |
| | — |
|
| Net cash flows used in investing activities | (654 | ) | | (628 | ) | | (616 | ) |
| Cash flows from financing activities | | | | | |
| Changes in short-term borrowings | 14 |
| | 3 |
| | (41 | ) |
| Issuance of long-term debt | 200 |
| | 202 |
| | 4 |
|
| Retirement of long-term debt | (14 | ) | | (13 | ) | | (11 | ) |
| Dividends paid on common stock | (169 | ) | | (133 | ) | | (136 | ) |
| Contributions from parent | 166 |
| | 161 |
| | 187 |
|
| Other financing activities | (4 | ) | | (1 | ) | | (3 | ) |
| Net cash flows provided by financing activities | 193 |
| | 219 |
| | — |
|
| Increase (decrease) in cash, cash equivalents and restricted cash | 13 |
| | (2 | ) | | 35 |
|
| Cash, cash equivalents and restricted cash at beginning of period | 40 |
| | 42 |
| | 7 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 53 |
| | $ | 40 |
| | $ | 42 |
|
See the Combined Notes to Consolidated Financial Statements
243210
Potomac Electric Power Company
Balance Sheets
| | | | | | | | | | | |
| December 31, |
| (In millions) | 2020 | | 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 30 | | | $ | 30 | |
| Restricted cash and cash equivalents | 35 | | | 33 | |
| Accounts receivable | | | |
| Customer accounts receivable | 279 | | 244 |
| Customer allowance for credit losses | (32) | | (13) |
| Customer accounts receivable, net | 247 | | | 231 | |
| Other accounts receivable | 131 | | 98 |
| Other allowance for credit losses | (13) | | (7) |
| Other accounts receivable, net | 118 | | | 91 | |
| | | |
| Receivables from affiliates | 2 | | | 0 | |
| | | |
| | | |
| Inventories, net | 111 | | | 112 | |
| Regulatory assets | 214 | | | 188 | |
| | | |
| Other | 13 | | | 11 | |
| Total current assets | 770 | | | 696 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $3,697 and $3,517 as of December 31, 2020 and 2019, respectively) | 7,456 | | | 6,909 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 570 | | | 584 | |
| Investments | 115 | | | 110 | |
| | | |
| Prepaid pension asset | 284 | | | 296 | |
| Other | 69 | | | 66 | |
| Total deferred debits and other assets | 1,038 | | | 1,056 | |
| Total assets | $ | 9,264 | | | $ | 8,661 | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 16 |
| | $ | 5 |
|
| Restricted cash and cash equivalents | 37 |
| | 35 |
|
| Accounts receivable, net | | | |
| Customer | 225 |
| | 250 |
|
| Other | 81 |
| | 87 |
|
| Receivables from affiliates | 1 |
| | — |
|
| Inventories, net | 93 |
| | 87 |
|
| Regulatory assets | 270 |
| | 213 |
|
| Other | 37 |
| | 33 |
|
| Total current assets | 760 |
| | 710 |
|
| Property, plant and equipment, net | 6,460 |
| | 6,001 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 643 |
| | 678 |
|
| Investments | 105 |
| | 102 |
|
| Prepaid pension asset | 316 |
| | 322 |
|
| Other | 15 |
| | 19 |
|
| Total deferred debits and other assets | 1,079 |
|
| 1,121 |
|
| Total assets | $ | 8,299 |
| | $ | 7,832 |
|
See the Combined Notes to Consolidated Financial Statements
244211
Potomac Electric Power Company
Balance Sheets
| | | | | | | | | | | |
| December 31, |
| (In millions) | 2020 | | 2019 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 35 | | | $ | 82 | |
| Long-term debt due within one year | 3 | | | 2 | |
| Accounts payable | 226 | | | 195 | |
| Accrued expenses | 164 | | | 156 | |
| Payables to affiliates | 55 | | | 66 | |
| | | |
| | | |
| | | |
| Customer deposits | 51 | | | 57 | |
| Regulatory liabilities | 46 | | | 8 | |
| | | |
| Merger related obligation | 33 | | | 39 | |
| Current portion of DC PLUG obligation | 30 | | | 30 | |
| Other | 31 | | | 22 | |
| Total current liabilities | 674 | | | 657 | |
| Long-term debt | 3,162 | | | 2,862 | |
| | | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 1,189 | | | 1,131 | |
| Asset retirement obligations | 39 | | | 41 | |
| | | |
| Non-pension postretirement benefit obligations | 13 | | | 20 | |
| | | |
| Regulatory liabilities | 644 | | | 746 | |
| | | |
| | | |
| | | |
| Other | 340 | | | 297 | |
| Total deferred credits and other liabilities | 2,225 | | | 2,235 | |
| Total liabilities | 6,061 | | | 5,754 | |
| Commitments and contingencies | 0 | | 0 |
| Shareholder's equity | | | |
Common stock ($0.01 par value, 200 shares authorized, 0 shares(a) outstanding at December 31, 2020 and 2019) | 2,058 | | | 1,796 | |
| | | |
| | | |
| Retained earnings | 1,145 | | | 1,111 | |
| | | |
| Total shareholder's equity | 3,203 | | | 2,907 | |
| Total liabilities and shareholder's equity | $ | 9,264 | | | $ | 8,661 | |
|
| | | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 40 |
| | $ | 26 |
|
| Long-term debt due within one year | 15 |
| | 19 |
|
| Accounts payable | 214 |
| | 139 |
|
| Accrued expenses | 126 |
| | 137 |
|
| Payables to affiliates | 62 |
| | 74 |
|
| Regulatory liabilities | 7 |
| | 3 |
|
| Customer deposits | 54 |
| | 54 |
|
| Merger related obligation | 38 |
| | 42 |
|
| Current portion of DC PLUG obligation | 30 |
| | 28 |
|
| Other | 42 |
| | 28 |
|
| Total current liabilities | 628 |
| — |
| 550 |
|
| Long-term debt | 2,704 |
| | 2,521 |
|
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 1,064 |
| | 1,063 |
|
| Non-pension postretirement benefit obligations | 29 |
| | 36 |
|
| Regulatory liabilities | 822 |
| | 829 |
|
| Other | 312 |
| | 300 |
|
| Total deferred credits and other liabilities | 2,227 |
| | 2,228 |
|
| Total liabilities | 5,559 |
| | 5,299 |
|
| Commitments and contingencies |
| |
|
| Shareholder's equity | | | |
| Common stock | 1,636 |
| | 1,470 |
|
| Retained earnings | 1,104 |
| | 1,063 |
|
| Total shareholder's equity | 2,740 |
| | 2,533 |
|
| Total liabilities and shareholder's equity | $ | 8,299 |
|
| $ | 7,832 |
|
(a)In millions, shares round to zero. Number of shares is 100 outstanding at December 31, 2020 and 2019.
See the Combined Notes to Consolidated Financial Statements
245212
Potomac Electric Power Company
Statements of Changes in Shareholder's Equity
| | | | | | | | | | | | | | | | | |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2017 | $ | 1,470 | | | $ | 1,045 | | | $ | 2,515 | |
| Net income | — | | | 205 | | | 205 | |
| Common stock dividends | — | | | (169) | | | (169) | |
| Contributions from parent | 166 | | | — | | | 166 | |
| Balance, December 31, 2018 | $ | 1,636 | | | $ | 1,081 | | | $ | 2,717 | |
| Net income | — | | | 243 | | | 243 | |
| Common stock dividends | — | | | (213) | | | (213) | |
| Contributions from parent | 160 | | | — | | | 160 | |
| Balance, December 31, 2019 | $ | 1,796 | | | $ | 1,111 | | | $ | 2,907 | |
| Net income | — | | | 266 | | | 266 | |
| Common stock dividends | — | | | (232) | | | (232) | |
| Contributions from parent | 262 | | | — | | | 262 | |
| Balance, December 31, 2020 | $ | 2,058 | | | $ | 1,145 | | | $ | 3,203 | |
|
| | | | | | | | | | | |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2015 | $ | 1,122 |
| | $ | 1,118 |
| | $ | 2,240 |
|
| Net income | — |
| | 42 |
| | 42 |
|
| Common stock dividends | — |
| | (169 | ) | | (169 | ) |
| Contributions from parent | 187 |
| | — |
| | 187 |
|
| Balance, December 31, 2016 | $ | 1,309 |
| | $ | 991 |
| | $ | 2,300 |
|
| Net income | — |
| | 205 |
| | 205 |
|
| Common stock dividends | — |
| | (133 | ) | | (133 | ) |
| Contributions from parent | 161 |
| | — |
| | 161 |
|
| Balance, December 31, 2017 | $ | 1,470 |
| | $ | 1,063 |
| | $ | 2,533 |
|
| Net income | — |
| | 210 |
| | 210 |
|
| Common stock dividends | — |
| | (169 | ) | | (169 | ) |
| Contributions from parent | 166 |
| | — |
| | 166 |
|
| Balance, December 31, 2018 | $ | 1,636 |
| | $ | 1,104 |
| | $ | 2,740 |
|
See the Combined Notes to Consolidated Financial Statements
246213
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income (Loss)
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Operating revenues | | | | | |
| Electric operating revenues | $ | 1,107 | | | $ | 1,143 | | | $ | 1,139 | |
| Natural gas operating revenues | 162 | | | 167 | | | 181 | |
| Revenues from alternative revenue programs | (7) | | | (11) | | | 4 | |
| Operating revenues from affiliates | 9 | | | 7 | | | 8 | |
| Total operating revenues | 1,271 | | | 1,306 | | | 1,332 | |
| Operating expenses | | | | | |
| Purchased power | 359 | | | 381 | | | 352 | |
| Purchased fuel | 69 | | | 75 | | | 89 | |
| Purchased power from affiliates | 75 | | | 70 | | | 120 | |
| Operating and maintenance | 208 | | | 171 | | | 182 | |
| Operating and maintenance from affiliates | 153 | | | 152 | | | 162 | |
| Depreciation and amortization | 191 | | | 184 | | | 182 | |
| Taxes other than income taxes | 65 | | | 56 | | | 56 | |
| Total operating expenses | 1,120 | | | 1,089 | | | 1,143 | |
| Gain on sales of assets | 0 | | | 0 | | | 1 | |
| Operating income | 151 | | | 217 | | | 190 | |
| Other income and (deductions) | | | | | |
| Interest expense, net | (61) | | | (61) | | | (58) | |
| Other, net | 10 | | | 13 | | | 10 | |
| Total other income and (deductions) | (51) | | | (48) | | | (48) | |
| Income before income taxes | 100 | | | 169 | | | 142 | |
| Income taxes | (25) | | | 22 | | | 22 | |
| Net income | $ | 125 | | | $ | 147 | | | $ | 120 | |
| Comprehensive income | $ | 125 | | | $ | 147 | | | $ | 120 | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Operating revenues | | | | | |
| Electric operating revenues | $ | 1,139 |
| | $ | 1,125 |
| | $ | 1,128 |
|
| Natural gas operating revenues | 181 |
| | 161 |
| | 148 |
|
| Revenues from alternative revenue programs | 4 |
| | 6 |
| | (6 | ) |
| Operating revenues from affiliates | 8 |
| | 8 |
| | 7 |
|
| Total operating revenues | 1,332 |
|
| 1,300 |
|
| 1,277 |
|
| Operating expenses | | | | | |
| Purchased power | 352 |
| | 282 |
| | 369 |
|
| Purchased fuel | 89 |
| | 71 |
| | 60 |
|
| Purchased power from affiliates | 120 |
| | 179 |
| | 154 |
|
| Operating and maintenance | 182 |
| | 283 |
| | 422 |
|
| Operating and maintenance from affiliates | 162 |
| | 32 |
| | 19 |
|
| Depreciation and amortization | 182 |
| | 167 |
| | 157 |
|
| Taxes other than income | 56 |
| | 57 |
| | 55 |
|
| Total operating expenses | 1,143 |
|
| 1,071 |
|
| 1,236 |
|
| Gain on sales of assets | 1 |
| | — |
| | 9 |
|
| Operating income | 190 |
|
| 229 |
|
| 50 |
|
| Other income and (deductions) | | | | | |
| Interest expense, net | (58 | ) | | (51 | ) | | (50 | ) |
| Other, net | 10 |
| | 14 |
| | 13 |
|
| Total other income and (deductions) | (48 | ) |
| (37 | ) |
| (37 | ) |
| Income before income taxes | 142 |
|
| 192 |
|
| 13 |
|
| Income taxes | 22 |
| | 71 |
| | 22 |
|
| Net income (loss) | $ | 120 |
|
| $ | 121 |
|
| $ | (9 | ) |
| Comprehensive income (loss) | $ | 120 |
|
| $ | 121 |
|
| $ | (9 | ) |
See the Combined Notes to Consolidated Financial Statements
247214
Delmarva Power & Light Company
Statements of Cash Flows
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | g | 2018 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 125 | | | $ | 147 | | | $ | 120 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | |
| Depreciation and amortization | 191 | | | 184 | | | 182 | |
| | | | | |
| | | | | |
| Deferred income taxes and amortization of investment tax credits | (13) | | | (7) | | | 24 | |
| Other non-cash operating activities | 51 | | | 27 | | | 24 | |
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | (34) | | | (5) | | | 8 | |
| Receivables from and payables to affiliates, net | 8 | | | (5) | | | (9) | |
| Inventories | (5) | | | (6) | | | (3) | |
| Accounts payable and accrued expenses | 4 | | | 3 | | | 11 | |
| | | | | |
| Income taxes | (25) | | | 12 | | | 2 | |
| Pension and non-pension postretirement benefit contributions | 0 | | | (1) | | | 0 | |
| Other assets and liabilities | (30) | | | (55) | | | (7) | |
| Net cash flows provided by operating activities | 272 | | | 294 | | | 352 | |
| Cash flows from investing activities | | | | | |
| Capital expenditures | (424) | | | (348) | | | (364) | |
| | | | | |
| | | | | |
| Other investing activities | (3) | | | 1 | | | 2 | |
| Net cash flows used in investing activities | (427) | | | (347) | | | (362) | |
| Cash flows from financing activities | | | | | |
| Change in short-term borrowings | 90 | | | 56 | | | (216) | |
| Issuance of long-term debt | 178 | | | 75 | | | 200 | |
| Retirement of long-term debt | (80) | | | (12) | | | (4) | |
| Dividends paid on common stock | (141) | | | (139) | | | (96) | |
| Contributions from parent | 112 | | | 63 | | | 150 | |
| Other financing activities | (2) | | | (1) | | | (2) | |
| Net cash flows provided by financing activities | 157 | | | 42 | | | 32 | |
| Increase (decrease) in cash and cash equivalents | 2 | | | (11) | | | 22 | |
| Cash and cash equivalents at beginning of period | 13 | | | 24 | | | 2 | |
| Cash and cash equivalents at end of period | $ | 15 | | | $ | 13 | | | $ | 24 | |
| | | | | |
| Supplemental cash flow information | | | | | |
| Increase (decrease) in capital expenditures not paid | $ | 20 | | | $ | (4) | | | $ | 22 | |
| | | | | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Cash flows from operating activities | | | | | |
| Net income (loss) | $ | 120 |
| | $ | 121 |
| | $ | (9 | ) |
| Adjustments to reconcile net income (loss) to net cash flows provided by operating activities: | | | | | |
| Depreciation and amortization | 182 |
| | 167 |
| | 157 |
|
| Impairment losses on regulatory assets | — |
| | 6 |
| | — |
|
| Deferred income taxes and amortization of investment tax credits | 24 |
| | 89 |
| | 109 |
|
| Other non-cash operating activities | 24 |
| | 9 |
| | 114 |
|
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | 8 |
| | (22 | ) | | (5 | ) |
| Receivables from and payables to affiliates, net | (9 | ) | | 11 |
| | 13 |
|
| Inventories | (3 | ) | | (5 | ) | | — |
|
| Accounts payable and accrued expenses | 11 |
| | (8 | ) | | (4 | ) |
| Collateral received, net | — |
| | — |
| | 1 |
|
| Income taxes | 2 |
| | 26 |
| | 28 |
|
| Pension and non-pension postretirement benefit contributions | — |
| | (2 | ) | | (22 | ) |
| Other assets and liabilities | (7 | ) | | (71 | ) | | (72 | ) |
| Net cash flows provided by operating activities | 352 |
|
| 321 |
|
| 310 |
|
| Cash flows from investing activities | | | | | |
| Capital expenditures | (364 | ) | | (428 | ) | | (349 | ) |
| Other investing activities | 2 |
| | (1 | ) | | 13 |
|
| Net cash flows used in investing activities | (362 | ) |
| (429 | ) |
| (336 | ) |
| Cash flows from financing activities | | | | | |
| Change in short-term borrowings | (216 | ) | | 216 |
| | (105 | ) |
| Issuance of long-term debt | 200 |
| | — |
| | 175 |
|
| Retirement of long-term debt | (4 | ) | | (40 | ) | | (100 | ) |
| Dividends paid on common stock | (96 | ) | | (112 | ) | | (54 | ) |
| Contributions from parent | 150 |
| | — |
| | 152 |
|
| Other financing activities | (2 | ) | | — |
| | (1 | ) |
| Net cash flows provided by financing activities | 32 |
|
| 64 |
|
| 67 |
|
| Increase (decrease) in cash, cash equivalents and restricted cash | 22 |
| | (44 | ) | | 41 |
|
| Cash, cash equivalents and restricted cash at beginning of period | 2 |
| | 46 |
| | 5 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 24 |
|
| $ | 2 |
|
| $ | 46 |
|
See the Combined Notes to Consolidated Financial Statements
248215
Delmarva Power & Light Company
Balance Sheets
| | | | | | | | | | | |
| December 31, |
| (In millions) | 2020 | | 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 15 | | | $ | 13 | |
| | | |
| Accounts receivable | | | |
| Customer accounts receivable | 176 | | 152 |
| Customer allowance for credit losses | (22) | | (11) |
| Customer accounts receivable, net | 154 | | | 141 | |
| Other accounts receivable | 68 | | 42 |
| Other allowance for credit losses | (9) | | (4) |
| Other accounts receivable, net | 59 | | | 38 | |
| Receivables from affiliates | 1 | | | 0 | |
| Inventories, net | | | |
| Fossil fuel | 6 | | | 8 | |
| Materials and supplies | 51 | | | 44 | |
| Prepaid utility taxes | 11 | | | 18 | |
| Regulatory assets | 58 | | | 52 | |
| Renewable energy credits | 10 | | | 9 | |
| Other | 3 | | | 2 | |
| Total current assets | 368 | | | 325 | |
| Property, plant, and equipment, (net of accumulated depreciation and amortization of $1,533 and $1,425 as of December 31, 2020 and 2019, respectively) | 4,314 | | | 4,035 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 222 | | | 222 | |
| | | |
| Goodwill | 8 | | | 8 | |
| Prepaid pension asset | 162 | | | 171 | |
| Other | 66 | | | 69 | |
| Total deferred debits and other assets | 458 | | | 470 | |
| Total assets | $ | 5,140 | | | $ | 4,830 | |
| | | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 23 |
| | $ | 2 |
|
| Restricted cash and cash equivalents | 1 |
| | — |
|
| Accounts receivable, net | | | |
| Customer | 134 |
| | 146 |
|
| Other | 46 |
| | 38 |
|
| Inventories, net | | | |
| Gas held in storage | 9 |
| | 7 |
|
| Materials and supplies | 37 |
| | 36 |
|
| Regulatory assets | 59 |
| | 69 |
|
| Other | 27 |
| | 27 |
|
| Total current assets | 336 |
|
| 325 |
|
| Property, plant and equipment, net | 3,821 |
| | 3,579 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 231 |
| | 245 |
|
| Goodwill | 8 |
| | 8 |
|
| Prepaid pension asset | 186 |
| | 193 |
|
| Other | 6 |
| | 7 |
|
| Total deferred debits and other assets | 431 |
|
| 453 |
|
| Total assets | $ | 4,588 |
|
| $ | 4,357 |
|
See the Combined Notes to Consolidated Financial Statements
249216
Delmarva Power & Light Company
Balance Sheets
| | | | | | | | | | | |
| December 31, |
| (In millions) | 2020 | | 2019 |
| | | |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 146 | | | $ | 56 | |
| Long-term debt due within one year | 82 | | | 80 | |
| Accounts payable | 126 | | | 112 | |
| Accrued expenses | 46 | | | 46 | |
| Payables to affiliates | 36 | | | 32 | |
| Customer deposits | 32 | | | 36 | |
| Regulatory liabilities | 47 | | | 37 | |
| | | |
| Other | 20 | | | 15 | |
| Total current liabilities | 535 | | | 414 | |
| Long-term debt | 1,595 | | | 1,487 | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 715 | | | 655 | |
| Asset retirement obligations | 14 | | | 12 | |
| Non-pension postretirement benefit obligations | 15 | | | 16 | |
| Regulatory liabilities | 493 | | | 574 | |
| Other | 97 | | | 92 | |
| Total deferred credits and other liabilities | 1,334 | | | 1,349 | |
| Total liabilities | 3,464 | | | 3,250 | |
| Commitments and contingencies | 0 | | 0 |
| Shareholder's equity | | | |
Common stock ($2.25 par value, 0 shares(a) authorized, 0 shares(a) outstanding at December 31, 2020 and 2019, respectively) | 1,089 | | | 977 | |
| Retained earnings | 587 | | | 603 | |
| Total shareholder's equity | 1,676 | | | 1,580 | |
| Total liabilities and shareholder's equity | $ | 5,140 | | | $ | 4,830 | |
| | | |
| | | |
| | | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | — |
| | $ | 216 |
|
| Long-term debt due within one year | 91 |
| | 83 |
|
| Accounts payable | 111 |
| | 82 |
|
| Accrued expenses | 39 |
| | 35 |
|
| Payables to affiliates | 33 |
| | 46 |
|
| Regulatory liabilities | 59 |
| | 42 |
|
| Customer deposits | 35 |
| | 35 |
|
| Other | 7 |
| | 8 |
|
| Total current liabilities | 375 |
|
| 547 |
|
| Long-term debt | 1,403 |
| | 1,217 |
|
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 628 |
| | 603 |
|
| Non-pension postretirement benefit obligations | 17 |
| | 14 |
|
| Regulatory liabilities | 606 |
| | 593 |
|
| Other | 50 |
| | 48 |
|
| Total deferred credits and other liabilities | 1,301 |
|
| 1,258 |
|
| Total liabilities | 3,079 |
|
| 3,022 |
|
| Commitments and contingencies |
|
| |
|
|
| Shareholder's equity | | | |
| Common stock | 914 |
| | 764 |
|
| Retained earnings | 595 |
| | 571 |
|
| Total shareholder's equity | 1,509 |
|
| 1,335 |
|
| Total liabilities and shareholder's equity | $ | 4,588 |
|
| $ | 4,357 |
|
(a)In millions, shares round to zero. Number of shares is 1,000 authorized and 1,000 outstanding at December 31, 2020 and 2019.
See the Combined Notes to Consolidated Financial Statements
250217
Delmarva Power & Light Company
Statements of Changes in Shareholder's Equity
| | | | | | | | | | | | | | | | | |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2017 | $ | 764 | | | $ | 571 | | | $ | 1,335 | |
| Net income | — | | | 120 | | | 120 | |
| Common stock dividends | — | | | (96) | | | (96) | |
| Contributions from parent | 150 | | | — | | | 150 | |
| Balance, December 31, 2018 | $ | 914 | | | $ | 595 | | | $ | 1,509 | |
| Net income | — | | | 147 | | | 147 | |
| Common stock dividends | — | | | (139) | | | (139) | |
| Contributions from parent | 63 | | | — | | | 63 | |
| Balance, December 31, 2019 | $ | 977 | | | $ | 603 | | | $ | 1,580 | |
| Net income | — | | | 125 | | | 125 | |
| Common stock dividends | — | | | (141) | | | (141) | |
| Contributions from parent | 112 | | | — | | | 112 | |
| Balance, December 31, 2020 | $ | 1,089 | | | $ | 587 | | | $ | 1,676 | |
|
| | | | | | | | | | | |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2015 | $ | 612 |
| | $ | 625 |
| | $ | 1,237 |
|
| Net loss | — |
| | (9 | ) | | (9 | ) |
| Common stock dividends | — |
| | (54 | ) | | (54 | ) |
| Contributions from parent | 152 |
| | — |
| | 152 |
|
| Balance, December 31, 2016 | $ | 764 |
| | $ | 562 |
|
| $ | 1,326 |
|
| Net income | — |
| | 121 |
| | 121 |
|
| Common stock dividends | — |
| | (112 | ) | | (112 | ) |
| Balance, December 31, 2017 | $ | 764 |
| | $ | 571 |
|
| $ | 1,335 |
|
| Net income | — |
| | 120 |
| | 120 |
|
| Common stock dividends | — |
| | (96 | ) | | (96 | ) |
| Contributions from parent | 150 |
| | — |
| | 150 |
|
| Balance, December 31, 2018 | $ | 914 |
| | $ | 595 |
|
| $ | 1,509 |
|
See the Combined Notes to Consolidated Financial Statements
251218
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Operations and Comprehensive Income (Loss)
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Operating revenues | | | | | |
| Electric operating revenues | $ | 1,253 | | | $ | 1,237 | | | $ | 1,237 | |
| Revenues from alternative revenue programs | (12) | | | 0 | | | (4) | |
| Operating revenues from affiliates | 4 | | | 3 | | | 3 | |
| Total operating revenues | 1,245 | | | 1,240 | | | 1,236 | |
| Operating expenses | | | | | |
| Purchased power | 596 | | | 589 | | | 587 | |
| Purchased power from affiliate | 13 | | | 19 | | | 29 | |
| Operating and maintenance | 192 | | | 187 | | | 188 | |
| Operating and maintenance from affiliates | 134 | | | 133 | | | 142 | |
| Depreciation and amortization | 180 | | | 157 | | | 136 | |
| Taxes other than income taxes | 8 | | | 4 | | | 5 | |
| Total operating expenses | 1,123 | | | 1,089 | | | 1,087 | |
| Gain on sale of assets | 2 | | | 0 | | | 0 | |
| | | | | |
| | | | | |
| Operating income | 124 | | | 151 | | | 149 | |
| Other income and (deductions) | | | | | |
| Interest expense, net | (59) | | | (58) | | | (64) | |
| Other, net | 6 | | | 6 | | | 2 | |
| Total other income and (deductions) | (53) | | | (52) | | | (62) | |
| Income before income taxes | 71 | | | 99 | | | 87 | |
| Income taxes | (41) | | | 0 | | | 12 | |
| | | | | |
| Net income | $ | 112 | | | $ | 99 | | | $ | 75 | |
| Comprehensive income | $ | 112 | | | $ | 99 | | | $ | 75 | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Operating revenues | | | | | |
| Electric operating revenues | $ | 1,237 |
| | $ | 1,176 |
| | $ | 1,245 |
|
| Revenues from alternative revenue programs | (4 | ) | | 8 |
| | 9 |
|
| Operating revenues from affiliates | 3 |
| | 2 |
| | 3 |
|
| Total operating revenues | 1,236 |
|
| 1,186 |
|
| 1,257 |
|
| Operating expenses | | | | | |
| Purchased power | 587 |
| | 541 |
| | 614 |
|
| Purchased power from affiliates | 29 |
| | 29 |
| | 37 |
|
| Operating and maintenance | 188 |
| | 279 |
| | 410 |
|
| Operating and maintenance from affiliates | 142 |
| | 28 |
| | 18 |
|
| Depreciation and amortization | 136 |
| | 146 |
| | 165 |
|
| Taxes other than income | 5 |
| | 6 |
| | 7 |
|
| Total operating expenses | 1,087 |
|
| 1,029 |
|
| 1,251 |
|
| Gain on sale of assets | — |
| | — |
| | 1 |
|
| Operating income | 149 |
|
| 157 |
|
| 7 |
|
| Other income and (deductions) | | | | | |
| Interest expense, net | (64 | ) | | (61 | ) | | (62 | ) |
| Other, net | 2 |
| | 7 |
| | 9 |
|
| Total other income and (deductions) | (62 | ) |
| (54 | ) |
| (53 | ) |
| Income (loss) before income taxes | 87 |
|
| 103 |
|
| (46 | ) |
| Income taxes | 12 |
| | 26 |
| | (4 | ) |
| Net income (loss) | $ | 75 |
|
| $ | 77 |
|
| $ | (42 | ) |
| Comprehensive income (loss) | $ | 75 |
|
| $ | 77 |
|
| $ | (42 | ) |
See the Combined Notes to Consolidated Financial Statements
252219
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Cash Flows
| | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Cash flows from operating activities | | | | | |
| Net income | $ | 112 | | | $ | 99 | | | $ | 75 | |
| Adjustments to reconcile net income to net cash from operating activities: | | | | | |
| Depreciation and amortization | 180 | | | 157 | | | 136 | |
| | | | | |
| Deferred income taxes and amortization of investment tax credits | (37) | | | 3 | | | 25 | |
| Other non-cash operating activities | 36 | | | 22 | | | 24 | |
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | (55) | | | (13) | | | (8) | |
| Receivables from and payables to affiliates, net | 6 | | | (6) | | | 1 | |
| Inventories | (3) | | | (1) | | | (4) | |
| Accounts payable and accrued expenses | 5 | | | 26 | | | (7) | |
| Income taxes | (1) | | | 2 | | | (2) | |
| Pension and non-pension postretirement benefit contributions | (2) | | | (1) | | | (6) | |
| Other assets and liabilities | (42) | | | (27) | | | (6) | |
| Net cash flows provided by operating activities | 199 | | | 261 | | | 228 | |
| Cash flows from investing activities | | | | | |
| Capital expenditures | (401) | | | (375) | | | (335) | |
| | | | | |
| | | | | |
| Other investing activities | 6 | | | (1) | | | 1 | |
| Net cash flows used in investing activities | (395) | | | (376) | | | (334) | |
| Cash flows from financing activities | | | | | |
| Change in short-term borrowings | 117 | | | 56 | | | (94) | |
| Proceeds from short-term borrowings with maturities greater than 90 days | 0 | | | 0 | | | 125 | |
| Repayments of short-term borrowings with maturities greater than 90 days | 0 | | | (125) | | | 0 | |
| Issuance of long-term debt | 123 | | | 150 | | | 350 | |
| Retirement of long-term debt | (44) | | | (18) | | | (281) | |
| | | | | |
| Dividends paid on common stock | (114) | | | (124) | | | (59) | |
| Contributions from parent | 117 | | | 175 | | | 67 | |
| Other financing activities | (1) | | | (1) | | | (3) | |
| Net cash flows provided by financing activities | 198 | | | 113 | | | 105 | |
| Increase (decrease) in cash, restricted cash, and cash equivalents | 2 | | | (2) | | | (1) | |
| Cash, restricted cash, and cash equivalents at beginning of period | 28 | | | 30 | | | 31 | |
| Cash, restricted cash, and cash equivalents at end of period | $ | 30 | | | $ | 28 | | | $ | 30 | |
| | | | | |
| Supplemental cash flow information | | | | | |
| Increase (decrease) in capital expenditures not paid | $ | 33 | | | $ | (29) | | | $ | 46 | |
| | | | | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Cash flows from operating activities | | | | | |
| Net income (loss) | $ | 75 |
| | $ | 77 |
| | $ | (42 | ) |
| Adjustments to reconcile net income (loss) to net cash from operating activities: | | | | | |
| Depreciation and amortization | 136 |
| | 146 |
| | 165 |
|
| Impairment losses on regulatory assets | — |
| | 7 |
| | — |
|
| Deferred income taxes and amortization of investment tax credits | 25 |
| | 32 |
| | 22 |
|
| Other non-cash operating activities | 24 |
| | 17 |
| | 155 |
|
| Changes in assets and liabilities: | | | | | |
| Accounts receivable | (8 | ) | | 14 |
| | (8 | ) |
| Receivables from and payables to affiliates, net | 1 |
| | — |
| | 13 |
|
| Inventories | (4 | ) | | (7 | ) | | (1 | ) |
| Accounts payable and accrued expenses | (7 | ) | | (2 | ) | | 9 |
|
| Income taxes | (2 | ) | | (11 | ) | | 174 |
|
| Pension and non-pension postretirement benefit contributions | (6 | ) | | (20 | ) | | (17 | ) |
| Other assets and liabilities | (6 | ) | | (47 | ) | | (85 | ) |
| Net cash flows provided by operating activities | 228 |
|
| 206 |
|
| 385 |
|
| Cash flows from investing activities | | | | | |
| Capital expenditures | (335 | ) | | (312 | ) | | (311 | ) |
| Other investing activities | 1 |
| | (1 | ) | | 4 |
|
| Net cash flows used in investing activities | (334 | ) |
| (313 | ) |
| (307 | ) |
| Cash flows from financing activities | | | | | |
| Change in short-term borrowings | (94 | ) | | 108 |
| | (5 | ) |
| Proceeds from short-term borrowings with maturities greater than 90 days | 125 |
| | — |
| | — |
|
| Issuance of long-term debt | 350 |
| | — |
| | — |
|
| Retirement of long-term debt | (281 | ) | | (35 | ) | | (48 | ) |
| Dividends paid on common stock | (59 | ) | | (68 | ) | | (63 | ) |
| Contributions from parent | 67 |
| | — |
| | 139 |
|
| Other financing activities | (3 | ) | | — |
| | (1 | ) |
| Net cash flows provided by financing activities | 105 |
|
| 5 |
|
| 22 |
|
| (Decrease) increase in cash, cash equivalents and restricted cash | (1 | ) |
| (102 | ) |
| 100 |
|
| Cash, cash equivalents and restricted cash at beginning of period | 31 |
| | 133 |
| | 33 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 30 |
|
| $ | 31 |
|
| $ | 133 |
|
See the Combined Notes to Consolidated Financial Statements
253220
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
| | | | | | | | | | | |
| December 31, |
| (In millions) | 2020 | | 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 17 | | | $ | 12 | |
| Restricted cash and cash equivalents | 3 | | | 2 | |
| Accounts receivable | | | |
| Customer accounts receivable | 156 | | 121 |
| Customer allowance for credit losses | (32) | | (13) |
| Customer accounts receivable, net | 124 | | | 108 | |
| Other accounts receivable | 72 | | 53 |
| Other allowance for credit losses | (11) | | (5) |
| Other accounts receivable, net | 61 | | | 48 | |
| | | |
| Receivables from affiliates | 6 | | | 4 | |
| | | |
| Inventories, net | 37 | | | 34 | |
| | | |
| | | |
| | | |
| Regulatory assets | 75 | | | 57 | |
| Other | 3 | | | 5 | |
| Total current assets | 326 | | | 270 | |
| Property, plant, and equipment, (net of accumulated depreciation and amortization of $1,303 and $1,210 as of December 31, 2020 and 2019, respectively) | 3,475 | | | 3,190 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 395 | | | 368 | |
| | | |
| | | |
| | | |
| Prepaid pension asset | 40 | | | 52 | |
| | | |
| Other | 50 | | | 53 | |
| Total deferred debits and other assets | 485 | | | 473 | |
Total assets(a) | $ | 4,286 | | | $ | 3,933 | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 7 |
| | $ | 2 |
|
| Restricted cash and cash equivalents | 4 |
| | 6 |
|
| Accounts receivable, net | | | |
| Customer | 95 |
| | 92 |
|
| Other | 55 |
| | 56 |
|
| Receivables from affiliates | 1 |
| | — |
|
| Inventories, net | 33 |
| | 29 |
|
| Regulatory assets | 40 |
| | 71 |
|
| Other | 5 |
| | 2 |
|
| Total current assets | 240 |
|
| 258 |
|
| Property, plant and equipment, net | 2,966 |
| | 2,706 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 386 |
| | 359 |
|
| Long-term note receivable | — |
| | 4 |
|
| Prepaid pension asset | 67 |
| | 73 |
|
| Other | 40 |
| | 45 |
|
| Total deferred debits and other assets | 493 |
|
| 481 |
|
Total assets(a) | $ | 3,699 |
|
| $ | 3,445 |
|
See the Combined Notes to Consolidated Financial Statements
254221
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
| | | | December 31, | | December 31, |
| (In millions) | 2018 | | 2017 | (In millions) | 2020 | | 2019 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | | LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | | Current liabilities | |
| Short-term borrowings | $ | 139 |
| | $ | 108 |
| Short-term borrowings | $ | 187 | | | $ | 70 | |
| Long-term debt due within one year | 18 |
| | 281 |
| Long-term debt due within one year | 261 | | | 20 | |
| Accounts payable | 154 |
| | 118 |
| Accounts payable | 177 | | | 144 | |
| Accrued expenses | 35 |
| | 33 |
| Accrued expenses | 46 | | | 42 | |
| Payables to affiliates | 28 |
| | 29 |
| Payables to affiliates | 31 | | | 25 | |
| | Customer deposits | | Customer deposits | 23 | | | 25 | |
| Regulatory liabilities | 18 |
| | 11 |
| Regulatory liabilities | 44 | | | 25 | |
| Customer deposits | 26 |
| | 31 |
| |
| | Other | 4 |
| | 8 |
| Other | 11 | | | 9 | |
| Total current liabilities | 422 |
|
| 619 |
| Total current liabilities | 780 | | | 360 | |
| Long-term debt | 1,170 |
| | 840 |
| Long-term debt | 1,152 | | | 1,307 | |
| Deferred credits and other liabilities | | | | Deferred credits and other liabilities | |
| Deferred income taxes and unamortized investment tax credits | 535 |
| | 493 |
| Deferred income taxes and unamortized investment tax credits | 624 | | | 577 | |
| | Non-pension postretirement benefit obligations | 17 |
| | 14 |
| Non-pension postretirement benefit obligations | 17 | | | 17 | |
| | Regulatory liabilities | 402 |
| | 411 |
| Regulatory liabilities | 274 | | | 357 | |
| | Other | 27 |
| | 25 |
| Other | 48 | | | 39 | |
| Total deferred credits and other liabilities | 981 |
|
| 943 |
| Total deferred credits and other liabilities | 963 | | | 990 | |
Total liabilities(a) | 2,573 |
|
| 2,402 |
| Total liabilities(a) | 2,895 | | | 2,657 | |
| Commitments and contingencies |
| |
| Commitments and contingencies | 0 | | 0 |
| Shareholder's equity | | | | Shareholder's equity | |
| Common stock | 979 |
| | 912 |
| |
| Common stock ($3 par value, 25 shares authorized, 9 shares outstanding at December 31, 2020 and 2019) | | Common stock ($3 par value, 25 shares authorized, 9 shares outstanding at December 31, 2020 and 2019) | 1,271 | | | 1,154 | |
| Retained earnings | 147 |
| | 131 |
| Retained earnings | 120 | | | 122 | |
| | Total shareholder's equity | 1,126 |
|
| 1,043 |
| Total shareholder's equity | 1,391 | | | 1,276 | |
| Total liabilities and shareholder's equity | $ | 3,699 |
|
| $ | 3,445 |
| Total liabilities and shareholder's equity | $ | 4,286 | | | $ | 3,933 | |
_____________
| |
(a) | (a)ACE’s consolidated assets include $13 million and $17 million at December 31, 2020 and 2019, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $21 million and $41 millionat December 31, 2020 and 2019, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 23 - Variable Interest Entities for additional information. ACE’s consolidated assets include $23 million and $29 million at December 31, 2018 and 2017, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $59 million and $90 millionat December 31, 2018 and 2017, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 - Variable Interest Entities for additional information.
|
See the Combined Notes to Consolidated Financial Statements
255222
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Changes in Shareholder's Equity
| | | | | | | | | | | | | | | | | |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2017 | $ | 912 | | | $ | 131 | | | $ | 1,043 | |
| Net income | — | | | 75 | | | 75 | |
| Common stock dividends | — | | | (59) | | | (59) | |
| Contributions from parent | 67 | | | — | | | 67 | |
| Balance, December 31, 2018 | $ | 979 | | | $ | 147 | | | $ | 1,126 | |
| Net income | — | | | 99 | | | 99 | |
| Common stock dividends | — | | | (124) | | | (124) | |
| Contributions from parent | 175 | | | — | | | 175 | |
| Balance, December 31, 2019 | $ | 1,154 | | | $ | 122 | | | $ | 1,276 | |
| Net income | — | | | 112 | | | 112 | |
| | | | | |
| | | | | |
| Common stock dividends | — | | | (114) | | | (114) | |
| Contributions from parent | 117 | | | — | | | 117 | |
| Balance, December 31, 2020 | $ | 1,271 | | | $ | 120 | | | $ | 1,391 | |
|
| | | | | | | | | | | |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2015 | $ | 773 |
| | $ | 227 |
| | $ | 1,000 |
|
| Net loss | — |
| | (42 | ) | | (42 | ) |
| Common stock dividends | — |
| | (63 | ) | | (63 | ) |
| Contributions from parent | 139 |
| | — |
| | 139 |
|
| Balance, December 31, 2016 | $ | 912 |
|
| $ | 122 |
| | $ | 1,034 |
|
| Net income | — |
| | 77 |
| | 77 |
|
| Common stock dividends | — |
| | (68 | ) | | (68 | ) |
| Balance, December 31, 2017 | $ | 912 |
|
| $ | 131 |
| | $ | 1,043 |
|
| Net income | — |
| | 75 |
| | 75 |
|
| Common stock dividends | — |
| | (59 | ) | | (59 | ) |
| Contribution from parent | 67 |
| | — |
| | 67 |
|
| Balance, December 31, 2018 | $ | 979 |
|
| $ | 147 |
| | $ | 1,126 |
|
See the Combined Notes to Consolidated Financial Statements
256223
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Index to Combined Notes to Consolidated Financial Statements
The notes to the consolidated financial statements that follow are a combined presentation. The following list indicates the Registrants to which the footnotes apply:
Applicable Notes
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant | 1 | 2 | 3 | 4 | 5 | 6 | 7 | 8 | 9 | 10 | 11 | 12 | 13 | 14 | 15 | 16 | 17 | 18 | 19 | 20 | 21 | 22 | 23 | 24 | 25 | 26 | 27 |
| Exelon Corporation | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . |
| Exelon Generation Company, LLC | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | | . | | . | . | . | . | . | . | . |
| Commonwealth Edison Company | . | . | . | . | | . | | | | . | . | . | . | . | . | . | . | . | . | | | . | . | . | . | . | |
| PECO Energy Company | . | . | . | . | | . | | | . | . | . | . | . | . | . | . | . | . | . | | . | . | . | . | . | . | |
| Baltimore Gas and Electric Company | . | . | . | . | | . | | | . | | . | . | . | . | . | . | . | . | . | | | . | . | . | . | . | |
| Pepco Holdings LLC | . | . | . | . | . | . | . | | . | . | . | . | . | . | . | . | . | | . | | | . | . | . | . | . | |
| Potomac Electric Power Company | . | . | . | . | . | . | . | | . | . | . | . | . | . | . | . | . | . | . | | | . | . | . | . | . | |
| Delmarva Power & Light Company | . | . | . | . | . | . | . | | . | . | . | . | . | . | . | . | . | . | . | | | . | . | . | . | . | |
| Atlantic City Electric Company | . | . | . | . | . | . | . | | . | . | . | . | . | . | . | . | . | . | . | | | . | . | . | . | . | |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
1. Significant Accounting Policies (All Registrants)
Description of Business (All Registrants)
Exelon is a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE. On March 23, 2016, Exelon completed the merger with PHI, which became a wholly owned subsidiary of Exelon. PHI is a utility services holding company engaged through its principal wholly owned subsidiaries, Pepco, DPL and ACE, in the energy distribution and transmission businesses. See Note 5 — Mergers, Acquisitions and Dispositions for additional information regarding the merger transaction.
|
| | | | | | | | | | | | | |
| Name of Registrant | | Business | | Service Territories |
Exelon Generation
Company, LLC | | Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy, and other energy-related products and services. | | SixFive reportable segments: Mid-Atlantic, Midwest, New England, New York, ERCOT, and Other Power Regions |
| | | | |
| Commonwealth Edison Company | | Purchase and regulated retail sale of electricity | | Northern Illinois, including the City of Chicago |
| | Transmission and distribution of electricity to retail customers | | |
| PECO Energy Company | | Purchase and regulated retail sale of electricity and natural gas | | Southeastern Pennsylvania, including the City of Philadelphia (electricity) |
| | Transmission and distribution of electricity and distribution of natural gas to retail customers | | Pennsylvania counties surrounding the City of Philadelphia (natural gas) |
| Baltimore Gas and Electric Company | | Purchase and regulated retail sale of electricity and natural gas | | Central Maryland, including the City of Baltimore (electricity and natural gas) |
| | Transmission and distribution of electricity and distribution of natural gas to retail customers | | |
| Pepco Holdings LLC | | Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE | | Service Territories of Pepco, DPL, and ACE |
| | | | |
Potomac Electric
Power Company | | Purchase and regulated retail sale of electricity | | District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland. |
| | Transmission and distribution of electricity to retail customers | | |
| Delmarva Power & Light Company | | Purchase and regulated retail sale of electricity and natural gas | | Portions of Delaware and Maryland (electricity) |
| | Transmission and distribution of electricity and distribution of natural gas to retail customers | | Portions of New Castle County, Delaware (natural gas) |
| Atlantic City Electric Company | | Purchase and regulated retail sale of electricity | | Portions of Southern New Jersey |
| | Transmission and distribution of electricity to retail customers | | |
Basis of Presentation (All Registrants)
This is a combined annual report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated above in the Index to Combined Notes to Consolidated Financial Statements and parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
As a result of the merger with PHI, Exelon’s financial reporting reflects PHI’s consolidated financial results subsequent to the March 23, 2016, acquisition date. Exelon has accounted for the merger transaction applying the acquisition method of accounting, which it has pushed-down to the consolidated financial statements of PHI such that the assets and liabilities of PHI are recorded at their respective fair values, and goodwill has been established as of the acquisition date. Accordingly, the consolidated financial statements of PHI for periods before and after the March 23, 2016, acquisition date reflect different bases of accounting, and the results of operations and the financial positions of the predecessor and successor periods are not comparable. The acquisition method of accounting has not been pushed down to PHI’s wholly owned subsidiary utility registrants, Pepco, DPL and ACE.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For financial statement purposes, beginning on March 24, 2016, disclosures related to Exelon also apply to PHI, Pepco, DPL and ACE, unless otherwise noted.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology, and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
Exelon owns 100% of Generation, PECO, BGE, and PHI and more than 99% of ComEd. PHI owns 100% of Pepco, DPL, and ACE. Generation owns 100% of its significant consolidated subsidiaries, either directly or
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
indirectly, except for certain consolidated VIEs, including CENG and EGRP, of which Generation holds a 50.01% and 51% interest, respectively. The remaining interests in these consolidated VIEs are included in noncontrolling interests on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 223 — Variable Interest Entities for additional information of Exelon’s and Generation’s consolidated VIEs.
The Registrants consolidate the accounts of entities in which a Registrant has a controlling financial interest, after the elimination of intercompany transactions. Where the Registrants do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting, or accounting for investments in equity securities with or without readily determinable fair value is applied. The Registrants apply proportionate consolidation when they have an undivided interest in an asset and are proportionately liable for their share of each liability associated with the asset. The Registrants proportionately consolidate their undivided ownership interests in jointly owned electric plants and transmission facilities. Under proportionate consolidation, the Registrants separately record their proportionate share of the assets, liabilities, revenues, and expenses related to the undivided interest in the asset. The Registrants apply equity method accounting when they have significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. The Registrants apply equity method accounting to certain investments and joint ventures, including certain financing trusts of ComEd and PECO.ventures. Under equity method accounting, the Registrants report their interest in the entity as an investment and the Registrants’ percentage share of the earnings from the entity as single line items in their financial statements. The Registrants use accounting for investments in equity securities with or without readily determinable fair values if they lack significant influence, which generally results when they hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the Registrants report their investment values based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the Registrants report their investments at cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changesimpairment, and changes in measurement are reported in earnings.
The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.
COVID-19 (All Registrants)
The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19). The Registrants provide a critical service to their customers and have taken measures to keep employees who operate the business safe and minimize unnecessary risk of exposure to the virus, including extra precautions for employees who work in the field. The Registrants have implemented work from home policies where appropriate and imposed travel limitations on employees. In addition, the Registrants have updated their existing business continuity plans.
Management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and accompanying notes, and the amounts of revenues and expenses reported during the periods covered by those financial statements and accompanying notes. Management assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to, the Registrants' allowance for credit losses and the carrying value of goodwill and other long-lived assets, in context with the information reasonably available to the Registrants and the unknown future impacts of COVID-19 as of December 31, 2020 and through the date of this report. The Registrants' future assessment of their current expectations of the magnitude and duration of COVID-19, as well as other factors, could result in material impacts to their consolidated financial statements in future reporting periods.
Use of Estimates (All Registrants)
The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and other postretirement benefits, the application of purchase accounting,OPEB, inventory reserves, allowance for uncollectible accounts,credit losses, goodwill and asset impairments,impairment assessments, derivative instruments, unamortized
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes, and unbilled energy revenues. Actual results could differ from those estimates.
Prior Period Adjustments and Reclassifications (All Registrants)
Certain prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows, Consolidated Balance Sheets and Consolidated Statements of Changes in Shareholders' Equity have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018. See New Accounting Standards below for additional information.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Accounting for the Effects of Regulation (Exelon and the Utility Registrants)
For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Exelon and the Utility Registrants account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, PAPUC, MDPSC, DCPSC, DPSC, and NJBPU, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon's regulatory assets and liabilities as of the balance sheet date are probable of being recovered or settled in future rates. If a separable portion of the Registrants' business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their financial statements. See Note 43 — Regulatory Matters for additional information.
With the exception of income tax-related regulatory assets and liabilities, Exelon and the Utility Registrants classify regulatory assets and liabilities with a recovery or settlement period greater than one year as both current and non-current in their Consolidated Balance Sheets, with the current portion representing the amount expected to be recovered from or settledrefunded to customers over the next twelve-month period as of the balance sheet date. Income tax-related regulatory assets and liabilities are classified entirely as non-current in Exelon's and the Utility Registrants’ Consolidated Balance Sheets to align with the classification of the related deferred income tax balances.
Exelon and the Utility Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.
Revenues (All Registrants)
Operating Revenues. The Registrants’ operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services, utility revenues from alternative revenue programs (ARP),ARP, and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and natural gas tariff sales, distribution, and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers.
ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco, and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. See Note 43 — Regulatory Matters and Note 23 — Supplemental Financial Information for additional information.
Option Contracts, Swaps, and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. To the extent a Utility Registrant receives full cost recovery for energy procurement and related costs from retail customers, it records the fair value of its energy swap contracts with unaffiliated suppliers as well as
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
an offsetting regulatory asset or liability in its Consolidated Balance Sheets. See Note 43 — Regulatory Matters and Note 1216 — Derivative Financial Instruments for additional information.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees, that are levied by state or local governments on the sale or distribution of gaselectricity and electricity.gas. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 2324 — Supplemental Financial Information for Generation’s ComEd’s, PECO’s, BGE’s, Pepco's, DPL's and ACE'sthe Utility Registrants' utility taxes that are presented on a gross basis.
Leases (All Registrants)
The Registrants adopted new accounting guidance issued by the FASB related to leases as of January 1, 2019. The Registrants recognize a ROU asset and lease liability for operating and finance leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. Finance lease ROU assets are included in Plant, property, and equipment, net and finance lease liabilities are included in Long-term debt due within one year and Long-term debt on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using each Registrant’s incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received), and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. The Registrants include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability.
Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation and are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements on the Registrants’ Statements of Operations and Comprehensive Income. Expense for finance leases is primarily recorded to Operating and maintenance on the Utility Registrants’ Statements of Operations and Comprehensive Income.
Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation and are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues on the Registrants’ Statements of Operations and Comprehensive Income.
The Registrants’ operating and finance leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. The Registrants generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all of the economic benefits. For new agreements entered after January 1, 2019, the Registrants generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. The Registrants account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases.
See Note 11 — Leases for additional information.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
Income Taxes (All Registrants)
Deferred Federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred in the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, income and deductionsnet (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in their Consolidated Statements of Operations and Comprehensive Income.
Pursuant to the IRC and relevant state taxing authorities, Exelon and its subsidiaries file consolidated or combined income tax returns for Federal and certain state jurisdictions where allowed or required. See Note 14 — Income Taxes for additional information.
Cash and Cash Equivalents (All Registrants)
The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Cash Equivalents (All Registrants)
Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 20182020 and 2017,2019, the Registrants' restricted cash and cash equivalents primarily represented the following items:
|
| | | | |
| Registrant | Description |
| Exelon | Payment of medical, dental, vision, and long-term disability benefits, in addition to the items listed for Generation and the Utility Registrants. |
| Generation | Project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. |
| ComEd | Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA, and costs for the remediation of an MGP site. |
| PECO | Proceeds from the sales of assets that were subject to PECO’s mortgage indenture. |
| BGE | Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers. |
| PHI | Payment of merger commitments, collateral held from its energy suppliers associated with procurement contracts, and repayment of transition bonds.Transition Bonds. |
| Pepco | Payment of merger commitments and collateral held from energy suppliers. |
| DPL | Collateral held from energy suppliers. |
| ACE | Repayment of transition bondsTransition Bonds and collateral held from energy suppliers. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 20182020 and 2017,2019, the Registrants' noncurrent restricted cash and cash equivalents primarily represented ComEd’s over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site, and ACE’s repayment of transition bonds.Transition Bonds.
See Note 2324 — Supplemental Financial Information for additional information.
Allowance for UncollectibleCredit Losses on Accounts Receivables (All Registrants)
The allowance for uncollectible accountscredit losses reflects the Registrants’ best estimates of losses on the customers' accounts receivable balances. For Generation, thebalances based on historical experience, current information, and reasonable and supportable forecasts.
The allowance for credit losses for Generation’s retail customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and other currentlyforward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available information. Utility Registrants estimatenews, payment status, payment history, and the
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
exercise of collateral calls. The allowance for credit losses for Generation wholesale customers is developed using a credit monitoring process, similar to that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, Generation uses specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense on Generation’s Consolidated Statements of Operations and Comprehensive Income.
The allowance for credit losses for the Utility Registrants’ customers is developed by applying loss rates developed specifically for each companyUtility Registrant, based on historical loss experience, current conditions, and forward-looking risk factors, to the outstanding receivable balance by customer risk segment. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Adjustments to the allowance for credit losses are primarily recorded to Operating and maintenance expense on the Utility Registrants' Consolidated Statements of Operations and Comprehensive Income or Regulatory assets and liabilities on the Utility Registrants' Consolidated Balance Sheets. See Note 4 —3 - Regulatory Matters for additional information regarding the regulatory recovery of uncollectiblecredit losses on customer accounts receivable at ComEdreceivable.
The Registrants have certain non-customer receivables in Other deferred debits and ACE.other assets which primarily are with governmental agencies and other high-quality counterparties with no history of default. As such, the allowance for credit losses related to these receivables is not material. The Registrants monitor these balances and will record an allowance if there are indicators of a decline in credit quality.
Variable Interest Entities (All Registrants)(Exelon, Generation, PHI, and ACE)
Exelon accounts for its investments in and arrangements with VIEs based on the following specific requirements:
•requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity has a controlling financial interest,
•requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, and
•requires the entity that consolidates a VIE (the primary beneficiary) to disclose (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.
See Note 223 — Variable Interest Entities for additional information.
Inventories (All Registrants)
Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Fossil fuel, materials and supplies, and emissions allowances are generally included in inventory when purchased. Fossil fuel and emissions allowances are expensed to purchased power and fuel expense when used or sold. Materials and supplies generally includes transmission, distribution, and generating plant materials and are expensed to operating and maintenance or capitalized to property, plant, and equipment, as appropriate, when installed or used.
Debt and Equity Security Investments (Exelon and Generation) Generation)
Debt Security Investments. Debt securities are reported at fair value and classified as available-for-sale securities. Unrealized gains and losses, net of tax, are reported in OCI.
Equity Security Investments without Readily Determinable Fair Values. Exelon has certain equity securities without readily determinable fair values. Exelon has elected to use the practicability exception to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in earnings.
Equity Security Investments with Readily Determinable Fair Values. Equity securities held in the NDT funds are classified asExelon has certain equity securities with readily determinable fair values. RealizedFor equity securities held in NDT funds, realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Regulatory Agreement Units are included in regulatory liabilities at Exelon, ComEd, and PECO, and in Noncurrent payables to affiliates at Generation and in
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
Noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Non-Regulatory Agreement Units are included in earnings at Exelon and Generation. Exelon's and Generation's NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. For all other equity securities with readily determinable fair values, realized and unrealized gains and losses are included in earnings at Exelon and Generation. See Note 43 — Regulatory Matters for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities and Note 1118 —
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Fair Value of Financial Assets and Liabilities and Note 1510 — Asset Retirement Obligations for additional information regarding marketable securities held by NDT funds.information.
Property, Plant, and Equipment (All Registrants)
Property, plant, and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. The Utility Registrants also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes capitalized interest for Generation, Exelon Corporate, and PHI and AFUDC for regulated property at the Utility Registrants. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred.
Third parties reimburse the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, plant, and equipment, net. DOE SGIG and other funds reimbursed to the Utility Registrants have been accounted for as CIAC.
For Generation, upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred.
For the Utility Registrants, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation consistent with the composite and group methods of depreciation. Depreciation expense at ComEd, BGE, Pepco, DPL, and ACE includes the estimated cost of dismantling and removing plant from service upon retirement. Actual incurred removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of previously collected removal costs. PECO’s removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method.
Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized within Property, plant, and equipment. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized within Other Current Assets and Deferred Debits and Other Assets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements.
Capitalized Interest and AFUDC. During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense.
AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to an allowance that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.
See Note 68 — Property, Plant, and Equipment, Note 9 — Jointly Owned Electric Utility Plant and Note 2324 — Supplemental Financial Information for additional information regarding property, plant and equipment.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
Nuclear Fuel (Exelon and Generation)
The cost of nuclear fuel is capitalized within Property, plant, and equipment and charged to fuel expense using the unit-of-production method. Any potential future SNF disposal fees will be expensed through fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 2219 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Nuclear Outage Costs (Exelon and Generation)
Costs associated with nuclear outages, including planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment (based on the nature of the activities) in the period incurred.
Depreciation and Amortization (All Registrants)
Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant, and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The Utility Registrants'ComEd, BGE, Pepco, DPL, and ACE's depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. PECO's removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO's regulatory recovery method. The estimated service lives for the Registrants are based on a combination of depreciation studies, historical retirements, site licenses, and management estimates of operating costs and expected future energy market conditions. See Note 87 — Early Plant Retirements for additional information on the impacts of expected and potential early plant retirements.
See Note 68 — Property, Plant, and Equipment for additional information regarding depreciation.
Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory order or agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have originally been recorded in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s electric distribution and energy efficiency formula rate regulatory assets and the Utility Registrants' transmission formula rate regulatory assets is recorded to Operating revenues.
Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of the regulatory assets and liabilities discussed above, when the recovery period is more than one year, the amortization is generally recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
See Note 43 — Regulatory Matters and Note 2324 — Supplemental Financial Information for additional information regarding Generation’s nuclear fuel and ARC, and the amortization of the Utility Registrants' regulatory assets.
Asset Retirement Obligations (All Registrants)
Generation estimates and recognizes a liability for its legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. Generation generally updates its nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within its probability-weighted discounted cash flow models. Generation’s multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through a decrease to regulatory liabilities for Regulatory Agreement Units or, in the case of the Utility Registrants' accretion, through an increase to regulatory assets. See Note 1510 — Asset Retirement Obligations for additional information.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
Guarantees (All Registrants)
TheIf necessary, the Registrants recognize a liability at the inceptiontime of issuance of a guarantee a liability for the fair market value of the obligations they have undertaken by issuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur.
guarantee. The liability that is initially recognized at the inception of the guarantee is reduced or eliminated as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
amortization method over the term of the guarantee. See Note 2219 — Commitments and Contingencies for additional information.
Asset Impairments
Long-Lived Assets (All Registrants). The Registrants regularly monitor and evaluate the carrying value of their long-lived assets orand asset groups excluding goodwill, whenfor recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets and asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. See Note 712 — Impairment of Long-Lived Assets and IntangiblesAsset Impairments for additional information.
Goodwill (Exelon, ComEd, and PHI). Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is testedassessed for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 1013 — Intangible Assets for additional information.
Equity Method Investments (Exelon and Generation). Exelon and Generation regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which Generation holds an investment recognizes an impairment loss, Exelon and Generation would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value.
Debt Security Investments (Exelon and Generation). Declines in the fair value of debt security investments below the cost basis are reviewed to determine if such decline isdeclines are other-than-temporary. If the decline is determined to be other-than-temporary, the amount of the impairment loss is included in earnings.
Equity Security Investments (Exelon and Generation). Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded through earnings. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired on the basis of the qualitative assessment, an impairment loss will be recognized in earnings to the amount by which the security’s carrying amount exceeds its fair value.
Derivative Financial Instruments (All Registrants)
All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception.NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenue, Purchased power and fuel, Interest expense, or Other, net in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While the majority of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to Exelon’s Risk Management Policy, and changes in the fair value of those derivatives are recorded in revenue in the Consolidated Statements of Operations and Comprehensive Income. At the Utility Registrants, changes in fair value may be recorded as a regulatory asset or liability if there is an ability to recover or return the associated costs. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
hedges. See Note 43 — Regulatory Matters and Note 1216 — Derivative Financial Instruments for additional information.
As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. Normal purchases and normal salesNPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as normal purchases and normal salesNPNS are recognized when the underlying physical transaction is
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. See Note 1216 — Derivative Financial Instruments for additional information.
Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and other postretirement benefitOPEB plans for essentially all current employees.
The measurement of the plan obligations and costs of providing benefits under these plans involveare measured as of December 31. The measurement involves various factors, assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and other postretirement benefitOPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 1615 — Retirement Benefits for additional information.
New Accounting Standards (All Registrants)
New Accounting Standards Adopted in 2018:2020: In 2018,2020, the Registrants adopted the following new authoritative accounting guidance issued by the FASB.
Defined Benefit Plan Disclosures (Issued August 2018). Eliminates existing disclosure requirements related to amounts in Accumulated other comprehensive income expected to be recognized in Net periodic benefit cost over the next year and the effects of a one-percentage-point change in the assumed health care cost trend rates. In addition, new disclosures were added such as the weighted-average interest crediting rates for cash balance plans and an explanation for the reasons for significant gains and losses related to changes in the benefit obligation. The standard is effective January 1, 2021, with early adoption permitted, and must be applied retrospectively. Exelon early adopted this standard in the fourth quarter of 2018. See Note 16 — Retirement Benefits for additional information.
Fair Value Measurement Disclosures (Issued August 2018). Updates the disclosure requirements for fair value measurements to improve the usefulness of information for financial statement users. The guidance removes the requirements to disclose (1) the amount of and reasons for transfers between Level 1 and Level 2, (2) the policy for timing of transfers between levels, and (3) the valuation processes for Level 3 fair value measurements and adds a requirement to disclose the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The standard is effective January 1, 2020, with early adoption permitted. The amendments to remove disclosures must be applied retrospectively and can be early adopted, while the amendments to add disclosures must be applied prospectively and adoption can be delayed until the effective date. The Registrants early adopted, in the fourth quarter of 2018, the amendments to remove disclosures and will adopt the amendments to add disclosures in the first quarter of 2020. The impact of the new disclosures is not expected to be material to the Registrants’ consolidated financial statements. See Note 11 — Fair Value of Financial Assets and Liabilities for additional information.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Issued February 2018). Provides an election for a reclassification from AOCI to Retained earnings to eliminate the stranded tax effects resulting from the TCJA. This standard is effective January 1, 2019, with early adoption permitted, and may be applied either in the period of adoption or retrospective to each period in which the effects of the TCJA were recognized. Exelon early adopted this standard and elected to apply the guidance retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million in its Consolidated Balance Sheet and Consolidated Statement of Changes in Shareholders' Equity related to deferred income taxes associated with Exelon’s pension and OPEB obligations. There was no impact for Generation or the Utility Registrants. Exelon's accounting policy is to release the stranded tax effects from AOCI related to its pension and OPEB plans under a portfolio (or aggregate) approach as an entire pension or OPEB plan is liquidated or terminated. See Note 21— Changes in Accumulated Other Comprehensive Income for additional information.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (Issued March 2017). Changes the accounting and presentation of pension and OPEB costs at the plan sponsor (i.e., Exelon) level. The guidance requires plan sponsors to report the service cost and other non-service cost components of net periodic pension cost and net periodic OPEB cost (together, net benefit cost) separately. Under the new guidance,
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
service cost is presented as part of income from operations and the other non-service cost components are classified outside of income from operations in the Consolidated Statements of Operations and Comprehensive Income. Additionally, service cost is the only component eligible for capitalization on a prospective basis beginning on January 1, 2018. Under prior GAAP, the total amount of net benefit cost was recorded as part of income from operations and all components were eligible for capitalization. Exelon applied the presentation of the service component and the other non-service cost components of net benefit costs retrospectively and, accordingly, have recasted those amounts, which were not material, in its Consolidated Statement of Operations and Comprehensive Income in prior periods presented. Exelon elected the practical expedient that permits an employer to use the amounts disclosed in its pension and other postretirement benefit plan note for the comparative periods as the estimation basis for applying the retrospective presentation requirements. In Exelon’s consolidated financial statements, non-service cost components of pension and OPEB cost capitalizable under a regulatory framework were prospectively reported as regulatory assets (previously, they were capitalizable under pension and OPEB accounting guidance and reported as PP&E). These regulatory assets are amortized outside of operating income. See Note 16 — Retirement Benefits for additional information.
Generation, ComEd, PECO, BGE, BSC, PHI, Pepco, DPL, ACE and PHISCO participate in Exelon’s single employer pension and OPEB plans and apply multi-employer accounting. Multi-employer accounting was not impacted by this standard; therefore, Exelon's subsidiary financial statements did not change upon its adoption.
Statement of Cash Flows: Classification of Restricted Cash (Issued November 2016). The standard states that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows (instead of being presented as cash flow activities). The Registrants applied the new guidance using the full retrospective method and, accordingly, have recasted the presentation of restricted cash in their Consolidated Statements of Cash Flows in the prior periods presented. See Note 23 — Supplemental Financial Information for additional information.
Recognition and Measurement of Financial Assets and Financial Liabilities (Issued January 2016). Eliminates the available-for-sale and cost method classification for equity securities and requires that all equity investments (other than those accounted for using the equity method of accounting) be measured and recorded at fair value with any changes in fair value recorded through earnings and, for equity investments without a readily determinable fair value, provides a measurement alternative of cost less impairment plus or minus adjustments for observable price changes in identical or similar assets. In addition, equity investments without readily determinable fair values must be qualitatively assessed for impairment each reporting period and fair value determined if any significant impairment indicators exist. If fair value is less than carrying value, the impairment is recorded through net income immediately in the period in which it is identified. The guidance does not impact the classification or measurement of investments in debt securities. The guidance also amends several disclosure requirements, including requiring i) financial assets and financial liabilities to be presented separately in the balance sheet or note, grouped by measurement category and form, ii) disclosure of the methods and significant assumptions used to estimate fair value or a description of the changes in the methods and assumptions used to estimate fair value, and iii) for financial assets and liabilities measured at amortized cost, disclosure of the fair value of the amount that would be received to sell the asset or paid to transfer the liability. The guidance was applied using a modified retrospective transition approach with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption. The Registrants recorded an insignificant adjustment to opening retained earnings as of January 1, 2018 related to unrealized gains/losses on available for sale equity securities. See Note 21— Changes in Accumulated Other Comprehensive Income for additional information.
Revenue from Contracts with Customers (Issued May 2014 and subsequently amended to address implementation questions). Changes the criteria for recognizing revenue from a contract with a customer. The new standard replaces existing guidance on revenue recognition, including most industry specific guidance, with a five-step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). The Registrants applied the new guidance using the full retrospective method
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
and, accordingly, have recasted certain amounts in their Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows, Consolidated Balance Sheets, Consolidated Statements of Changes in Shareholders' Equity and Combined Notes to Consolidated Financial Statements in the prior periods presented. The amounts recasted in the Registrants' 2017 and 2016 Consolidated Statements of Operations and Comprehensive Income are shown in the table below. The amounts recasted in the Registrants’ Consolidated Statements of Cash Flows, Consolidated Balance Sheets, Consolidated Statements of Changes in Shareholders' Equity and Combined Notes to Consolidated Financial Statements were not material. See Note 3 — Revenue from Contracts with Customers for additional information.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Successor | | | | | | |
| For the year ended December 31, 2017 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Operating Revenues - As reported | | | | | | | | | | | | | | | | | |
| Competitive business revenues | $ | 17,360 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Rate-regulated utility revenues | 16,171 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Operating revenues | — |
| | 17,351 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Electric operating revenues | — |
| | — |
| | 5,521 |
| | 2,369 |
| | 2,484 |
| | 4,468 |
| | 2,152 |
| | 1,131 |
| | 1,184 |
|
| Natural gas operating revenues | — |
| | — |
| | — |
| | 494 |
| | 676 |
| | 161 |
| | — |
| | 161 |
| | — |
|
| Operating revenues from affiliates | — |
| | 1,115 |
| | 15 |
| | 7 |
| | 16 |
| | 50 |
| | 6 |
| | 8 |
| | 2 |
|
| Total operating revenues | $ | 33,531 |
| | $ | 18,466 |
| | $ | 5,536 |
| | $ | 2,870 |
| | $ | 3,176 |
| | $ | 4,679 |
| | $ | 2,158 |
| | $ | 1,300 |
| | $ | 1,186 |
|
| | | | | | | | | | | | | | | | | | |
| Operating Revenues - Adjustments | | | | | | | | | | | | | | | | | |
| Competitive business revenues | $ | 34 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Rate-regulated utility revenues | (207 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Operating revenues | — |
| | 34 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Electric operating revenues | — |
| | — |
| | (43 | ) | | — |
| | (100 | ) | | (40 | ) | | (26 | ) | | (6 | ) | | (8 | ) |
| Natural gas operating revenues | — |
| | — |
| | — |
| | — |
| | (24 | ) | | — |
| | — |
| | — |
| | — |
|
| Revenues from alternative revenue programs | 207 |
| | — |
| | 43 |
| | — |
| | 124 |
| | 40 |
| | 26 |
| | 6 |
| | 8 |
|
| Operating revenues from affiliates | — |
| | — |
| | — |
| | — |
| |
|
| | — |
| | — |
| | — |
| | — |
|
| Total operating revenues | $ | 34 |
| | $ | 34 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | |
| Operating Revenues - Retrospective application | | | | | | | | | | | | | | | | | |
| Competitive business revenues | $ | 17,394 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Rate-regulated utility revenues | 15,964 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Operating revenues | — |
| | 17,385 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Electric operating revenues | — |
| | — |
| | 5,478 |
| | 2,369 |
| | 2,384 |
| | 4,428 |
| | 2,126 |
| | 1,125 |
| | 1,176 |
|
| Natural gas operating revenues | — |
| | — |
| | — |
| | 494 |
| | 652 |
| | 161 |
| | — |
| | 161 |
| | — |
|
| Revenues from alternative revenue programs | 207 |
| | — |
| | 43 |
| | — |
| | 124 |
| | 40 |
| | 26 |
| | 6 |
| | 8 |
|
| Operating revenues from affiliates | — |
| | 1,115 |
| | 15 |
| | 7 |
| | 16 |
| | 50 |
| | 6 |
| | 8 |
| | 2 |
|
| Total operating revenues | $ | 33,565 |
| | $ | 18,500 |
| | $ | 5,536 |
| | $ | 2,870 |
| | $ | 3,176 |
| | $ | 4,679 |
| | $ | 2,158 |
| | $ | 1,300 |
| | $ | 1,186 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| | | | | | | | | | | | | | | | | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| For the year ended December 31, 2016 | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
| Operating Revenues - As reported | | | | | | | | | | | | | | | | | | | | |
| Competitive business revenues | $ | 16,324 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
| Rate-regulated utility revenues | 15,036 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Operating revenues | — |
| | 16,312 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Electric operating revenues | — |
| | — |
| | 5,239 |
| | 2,524 |
| | 2,603 |
| | 2,181 |
| | 1,122 |
| | 1,254 |
| | 3,506 |
| | | 1,096 |
|
| Natural gas operating revenues | — |
| | — |
| | — |
| | 462 |
| | 609 |
| | — |
| | 148 |
| | — |
| | 92 |
| | | 57 |
|
| Operating revenues from affiliates | — |
| | 1,439 |
| | 15 |
| | 8 |
| | 21 |
| | 5 |
| | 7 |
| | 3 |
| | 45 |
| | | — |
|
| Total operating revenues | $ | 31,360 |
| | $ | 17,751 |
| | $ | 5,254 |
| | $ | 2,994 |
| | $ | 3,233 |
| | $ | 2,186 |
| | $ | 1,277 |
| | $ | 1,257 |
| | $ | 3,643 |
| | | $ | 1,153 |
|
| | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues - Adjustments | | | | | | | | | | | | | | | | | | | | |
| Competitive business revenues | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
| Rate-regulated utility revenues | (48 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Operating revenues | — |
| | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Electric operating revenues | — |
| | — |
| | 24 |
| | — |
| | (72 | ) | | (14 | ) | | 6 |
| | (9 | ) | | (43 | ) | | | 26 |
|
| Natural gas operating revenues | — |
| | — |
| | — |
| | — |
| | 19 |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Revenues from alternative revenue programs | 48 |
| | — |
| | (24 | ) | | — |
| | 53 |
| | 14 |
| | (6 | ) | | 9 |
| | 43 |
| | | (26 | ) |
| Operating revenues from affiliates | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Total operating revenues | $ | 6 |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues - Retrospective application | | | | | | | | | | | | | | | | | | | | |
| Competitive business revenues | $ | 16,330 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
| Rate-regulated utility revenues | 14,988 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Operating revenues | — |
| | 16,318 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Electric operating revenues | — |
| | — |
| | 5,263 |
| | 2,524 |
| | 2,531 |
| | 2,167 |
| | 1,128 |
| | 1,245 |
| | 3,463 |
| | | 1,122 |
|
| Natural gas operating revenues | — |
| | — |
| | — |
| | 462 |
| | 628 |
| | — |
| | 148 |
| | — |
| | 92 |
| | | 57 |
|
| Revenues from alternative revenue programs | 48 |
| | — |
| | (24 | ) | | — |
| | 53 |
| | 14 |
| | (6 | ) | | 9 |
| | 43 |
| | | (26 | ) |
| Operating revenues from affiliates | — |
| | 1,439 |
| | 15 |
| | 8 |
| | 21 |
| | 5 |
| | 7 |
| | 3 |
| | 45 |
| | | — |
|
| Total operating revenues | $ | 31,366 |
| | $ | 17,757 |
| | $ | 5,254 |
| | $ | 2,994 |
| | $ | 3,233 |
| | $ | 2,186 |
| | $ | 1,277 |
| | $ | 1,257 |
| | $ | 3,643 |
| | | $ | 1,153 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
New Accounting Standards Adopted as of January 1, 2019: The following new authoritative accounting guidance issued by the FASB was adopted as of January 1, 2019 and will be reflected by the Registrants in their consolidated financial statements beginning in the first quarter of 2019.
Cloud Computing Arrangements (Issued August 2018). Aligns the requirements for capitalizing costs incurred to implement a cloud computing arrangement with the internal-use software guidance. As a result, certain implementation costs incurred in a cloud computing arrangement that are currently expensed as incurred will be deferred and amortized over the non-cancellable term of the arrangement plus any reasonably certain renewal periods. The standard is effective January 1, 2020, with early adoption permitted, and can be applied using either a prospective or retrospective transition approach. A retrospective approach requires a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. The Registrants early adopted this standard using a prospective approach as of January 1, 2019. The new guidance is not expected to have a material impact on the Registrants’ financial statements.
Leases (Issued February 2016). Increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The Registrants adopted the standard on January 1, 2019.
The new standard requires lessees to recognize both the right-of-use assets and lease liabilities in the balance sheet for most leases, whereas under previous GAAP only finance lease liabilities (referred to as capital leases) were recognized in the balance sheet. In addition, the definition of a lease has been revised which may result in changes to the classification of an arrangement as a lease. Under the new standard, an arrangement that conveys the right to control the use of an identified asset by obtaining substantially all of its economic benefits and directing how it is used is a lease, whereas the previous definition focuses on the ability to control the use of the asset or to obtain its output. Quantitative and qualitative disclosures related to the amount, timing and judgments of an entity’s accounting for leases and the related cash flows are expanded. Disclosure requirements apply to both lessees and lessors, whereas previous disclosures related only to lessees. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. Lessor accounting is also largely unchanged.
The new standard provides a number of transition practical expedients, which the Registrants have elected, including:
a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases,
an implementation expedient which allows the requirements of the standard in the period of adoption with no restatement of prior periods, and
a land easement expedient which allows entities to not evaluate land easements under the new standard at adoption if they were not previously accounted for as leases.
The Registrants have assessed the lease standard and executed a detailed implementation plan in preparation for adoption, which included the following key activities:
Developed a complete lease inventory and abstracted the required data attributes into a lease accounting system that supports the Registrants' lease portfolios and integrates with existing systems.
Evaluated the transition practical expedients available under the standard.
Identified, assessed and documented technical accounting issues, policy considerations and financial reporting implications.
Identified and implemented changes to processes and controls to ensure all impacts of the new standard are effectively addressed.
The adoption of the new standard is expected to result in right of use assets and lease obligations for operating leases recorded in the Registrants’ Consolidated Balance Sheets on January 1, 2019 of approximately:
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | |
| Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE |
ROU Assets | $1,400-$1,500 | $1,000-$1,100 | $5-$10 | $1-$5 | $100-$120 | $250-$270 | $60-$65 | $70-$75 | $20-$25 |
Lease Liabilities | $1,600-$1,700 | $1,200-$1,300 | $5-$10 | $1-$5 | $100-$120 | $300-$320 | $60-$65 | $75-$80 | $20-$25 |
The impact of adopting the new standard on retained earnings as of January 1, 2019 is expected to be immaterial.
New Accounting Standards Issued and Not Yet Adopted as of December 31, 2018: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements as of December 31, 2018. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures, as well as the potential to early adopt where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation that such standards will not significantly impact the Registrants' financial reporting.
Goodwill Impairment (Issued January 2017). Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. Exelon, Generation, ComEd, PHI and DPL have goodwill as of December 31, 2018. This updated guidance is not currently expected to impact the Registrants’ financial reporting. The standard is effective January 1, 2020, with early adoption permitted, and must be applied on a prospective basis.
Impairment of Financial Instruments (Issued June 2016). Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments, and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects the entity’sits current estimate of credit losses expected to be incurred over the life of the financial instrument.instrument based on historical experience, current conditions, and reasonable and supportable forecasts. The standard does not make changes to the existing impairment models for non-financial assets such as fixed assets, intangibles and goodwill. The standard will bewas effective January 1, 2020 (with early adoption as of January 1, 2019 permitted) and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. This standard is primarily applicable to Generation's and the Utility Registrants' trade accounts receivables balances. The Registrants are currently assessingguidance did not have a significant impact on the impactsRegistrants' consolidated financial statements.
Goodwill Impairment (Issued January 2017). Simplifies the accounting for goodwill impairment by removing Step 2 of this standard.the current impairment assessment model, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment assessment). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment assessment is necessary. The standard was effective January 1, 2020 and must be applied on a prospective basis. Exelon, ComEd, and PHI adopted the new guidance in 2020. The new guidance did not impact Exelon's, ComEd's, and PHI's 2020 annual goodwill impairment assessments as they performed a qualitative assessment.
2. Variable Interest Entities (All Registrants)Mergers, Acquisitions, and Dispositions (Exelon and Generation)
A VIE isCENG Put Option (Exelon and Generation)
Generation owns a legal entity that possesses any50.01% membership interest in CENG, a joint venture with EDF, which wholly owns the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82% undivided ownership
At December 31, 2018 and 2017, Exelon, Generation, PHI and ACE collectively consolidated five VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated Variable Interest Entities below). As of December 31, 2018 and 2017, Exelon and Generation collectively had significant interests in seven other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated Variable Interest Entities below).
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 2 — Mergers, Acquisitions, and Dispositions
Consolidatedinterest in Nine Mile Point Unit 2. CENG is 100% consolidated in Exelon's and Generation's financial statements. See Note 23 — Variable Interest Entities for additional information.
The carrying amountsOn April 1, 2014, Generation and classificationEDF entered into various agreements including a NOSA, an amended LLC Operating Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others. Under the amended LLC Operating Agreement, CENG made a $400 million special distribution to EDF and committed to make preferred distributions to Generation until Generation has received aggregate distributions of $400 million plus a return of 8.50% per annum. Under the Put Option Agreement, EDF has the option to sell its 49.99% equity interest in CENG to Generation exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, Generation received notice of EDF’s intention to exercise the put option to sell its interest in CENG to Generation, and the put automatically exercised on January 19, 2020 at the end of the consolidated VIEs’ assets and liabilities included insixty-day advance notice period.
Under the Registrants' consolidated financial statements at December 31, 2018 and 2017 are as follows:
|
| | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | Exelon(a) | | Generation | | PHI(a) | | ACE |
| Current assets | $ | 938 |
| | $ | 931 |
| | $ | 7 |
| | 4 |
|
| Noncurrent assets | 9,071 |
| | 9,045 |
| | 26 |
| | 19 |
|
| Total assets | $ | 10,009 |
|
| $ | 9,976 |
|
| $ | 33 |
|
| $ | 23 |
|
| Current liabilities | $ | 274 |
| | $ | 252 |
| | $ | 22 |
| | 19 |
|
| Noncurrent liabilities | 3,280 |
| | 3,233 |
| | 47 |
| | 40 |
|
| Total liabilities | $ | 3,554 |
|
| $ | 3,485 |
|
| $ | 69 |
|
| $ | 59 |
|
|
| | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Exelon(a) | | Generation | | PHI(a) | | ACE |
| Current assets | $ | 662 |
| | $ | 652 |
| | $ | 10 |
| | $ | 6 |
|
| Noncurrent assets | 9,317 |
| | 9,286 |
| | 31 |
| | 23 |
|
| Total assets | $ | 9,979 |
| | $ | 9,938 |
| | $ | 41 |
| | $ | 29 |
|
| Current liabilities | $ | 308 |
| | $ | 272 |
| | $ | 36 |
| | $ | 32 |
|
| Noncurrent liabilities | 3,316 |
| | 3,250 |
| | 66 |
| | 58 |
|
| Total liabilities | $ | 3,624 |
| | $ | 3,522 |
| | $ | 102 |
| | $ | 90 |
|
__________
| |
(a) | Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity. |
Except as specifically noted below, the assets in the table above are restricted for settlementterms of the VIEPut Option Agreement, the purchase price is to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. The third parties determining fair market value of EDF’s 49.99% interest are to take into consideration all rights and obligations under the LLC Operating Agreement and Employee Matters Agreement including but not limited to Generation’s rights with respect to any unpaid aggregate preferred distributions and the liabilities in the table can only be settled using VIE resources.
related return. As of December 31, 20182020, the total unpaid aggregate preferred distributions and 2017, Exelon's and Generation's consolidated VIEs consist of:
Investments in Other Energy Related Companies
During 2015,related return owed to Generation sold 69% ofis $619 million. At this time, Generation cannot reasonably predict the ultimate purchase price that will be paid to EDF for its equity interest in a company to a tax equity investor.CENG. The company holds an equity method investment in a distributed energy company that is an unconsolidated VIE (see unconsolidated VIE section for additional details). Generationtransaction will require approval by the NYPSC and the tax equity investor contributed a totalFERC. The FERC approval was obtained on July 30, 2020. The process and regulatory approvals are expected to close in the second half of $227 million2021.
Agreement for Sale of equity in proportion to their ownership interests toGeneration’s Solar Business (Exelon and Generation)
On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the company. The company meets the definitionsale of a VIE because it has a similar structure to a limited partnership andsignificant portion of Generation’s solar business, including 360 megawatts of generation in operation or under construction across more than 600 sites across the limited partners do not have kick-out rights with respect toUnited States. Under the general partner. Generation is the primary beneficiary because Generation manages the day-to-day activitiesterms of the entity.transaction, the purchase price is $810 million, subject to certain working capital and other post-closing adjustments. Generation will retain certain solar assets not included in this agreement, primarily Antelope Valley.
DuringAs a result of the transaction, in the fourth quarter of 20172020, Exelon and Generation acquired a controlling financial interestreclassified the solar assets and liabilities on Exelon’s and Generation’s Consolidated Balance Sheets as held for sale. The transaction is expected to result in an energy development company.estimated pre-tax gain ranging from $75 million to $125 million. The companygain will be recorded in Gain on sales of assets and businesses in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income upon completion of the transaction. Completion of the transaction contemplated by the sale agreement is subject to the satisfaction of several closing conditions and is expected to occur in the development stagefirst half of 2021. See Note 17 — Debt and requiresCredit Agreements for additional subordinated financial supportinformation on the SolGen nonrecourse debt included as part of the transaction.
Disposition of Oyster Creek (Exelon and Generation)
On July 31, 2018, Generation entered into an agreement with Holtec and its indirect wholly owned subsidiary, OCEP, for the sale and decommissioning of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions, including approval of the license transfer from the equity holders to fund activities.NRC and other regulatory approvals, and a private letter ruling from the IRS, which were satisfied in the second quarter 2019. The sale was completed on July 1, 2019. Exelon and Generation isrecognized a loss on the majority owner with a 62% equity interest and hassale in the power to directthird quarter of 2019, which was immaterial.
Under the activities that most significantly affect the economic performanceterms of the company.
Renewable Energy Project Companies
In July 2017,transaction, Generation sold a 49% interesttransferred to OCEP substantially all the assets associated with Oyster Creek, including assets held in EGRP to an outside investorNDT funds, along with the assumption of liability for $400 millionall responsibility for the site, including full decommissioning and ongoing management of cash plus immaterial working capital and other customary post-closing adjustments. EGRP meetsspent fuel until the definition of a VIE because the EGRP has a similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. Generationspent fuel is the primary beneficiary because Generation manages the day-to-day activitiesmoved offsite. The terms of the entity; therefore,transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation will continue to consolidate EGRP. EGRP is a collectionupon the occurrence of wind and solar project entities and somespecified events.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 2 — Mergers, Acquisitions, and Dispositions
Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100%Upon remeasurement of the solar entitiesOyster Creek ARO, Exelon and 100%Generation recognized an $84 million and a $9 million pre-tax charge to Operating and maintenance expense in 2018 and in 2019, respectively. See Note 10 — Asset Retirement Obligations for additional information.
Disposition of Electrical Contracting Business (Exelon and Generation)
On February 28, 2018, Generation completed the sale of its interest in an electrical contracting business that primarily installs, maintains, and repairs underground and high-voltage cable transmission and distribution systems for $87 million, resulting in a pre-tax gain which is included within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2018.
3. Regulatory Matters (All Registrants)
The following matters below discuss the status of material regulatory and legislative proceedings of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance and there is limited recourse related to Generation related to certain solar and wind entities.Registrants.
While Generation or EGRP owns 100% of the majority of the wind entities, four of the projects have noncontrolling equity interests of 1% held by third parties and one of the projects has noncontrolling equity interests related to its Class B Membership Interest (see additional details below). The entities with noncontrolling equity interests of 1% held by third parties meet the definition of a VIE because the entities have noncontrolling equity interest holders that absorb variability from the wind projects. Generation’s or the EGRP's current economic interests in three of these projects is significantly greater than its stated contractual governance rights and all of these projects have reversionary interest provisions that provide the noncontrolling interest holder with a purchase option, certain of which are considered bargain purchase prices, which, if exercised, transfers ownership of the projects to the noncontrolling interest holder upon either the passage of time or the achievement of targeted financial returns. The ownership agreements with the noncontrolling interests state that Generation or EGRP are to provide financial support to the projects in proportion to its current 99% economic interests in the projects. Generation provides operating and capital funding to the wind project entities for ongoing construction, operations and maintenance and there is limited recourse to Generation related to certain wind project entities. However, no additional support to these projects beyond what was contractually required has been provided. Generation is the primary beneficiary of these wind entities because Generation controls the design, construction, and operation of the facilities.
In December 2016, Generation sold 100% of the Class B Membership Interests to a tax equity investor and retained 100% of the Class A Membership Interests of its equity interest in one of its wind entities that was previously consolidated under the voting interest model and was subsequently contributed to EGRP in 2017. The wind entity meets the definition of a VIE because the company has a similar structure to a limited partnershipUtility Regulatory Matters (Exelon, PHI, and the limited partners do not have kick-out rights with respectUtility Registrants)
Distribution Base Rate Case Proceedings
The following tables show the completed and pending distribution base rate case proceedings in 2020.
Completed Distribution Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement (Decrease) Increase | | Approved Revenue Requirement (Decrease) Increase | | Approved ROE | | Approval Date | | Rate Effective Date |
ComEd - Illinois(a) | | April 8, 2019 | | Electric | | $ | (6) | | | $ | (17) | | | 8.91 | % | | December 4, 2019 | | January 1, 2020 |
ComEd - Illinois(a) | | April 16, 2020 | | Electric | | (11) | | | (14) | | | 8.38 | % | | December 9, 2020 | | January 1, 2021 |
| | | | | | | | | | | | | | |
BGE - Maryland(b) | | May 15, 2020 (amended September 11, 2020) | | Electric | | 137 | | | 81 | | | 9.50 | % | | December 16, 2020 | | January 1, 2021 |
| | Natural Gas | | 91 | | | 21 | | | 9.65 | % | | |
| DPL - Maryland | | December 5, 2019 (amended April 23, 2020) | | Electric | | 17 | | | 12 | | | 9.60 | % | | July 14, 2020 | | July 16, 2020 |
| DPL - Delaware | | February 21, 2020 (amended October 9, 2020) | | Natural Gas | | 7 | | | 2 | | | 9.60 | % | | January 6, 2021 | | September 21, 2020 |
__________
(a)Pursuant to EIMA and FEJA, ComEd’s electric distribution rates are established through a performance-based formula, which sunsets at the general partner. While Generation is the minority interest holder, Generation is the primary beneficiary, because Generation manages the day-to-day activitiesend of the entity. Therefore, the entity continues to be consolidated by Generation.
In 2017, Generation’s interests in EGRP were contributed to2022. The electric distribution formula rate includes decoupling provisions and, are pledged for the ExGen Renewables IV non-recourse debt project financing structure. Refer to Note 13 — Debt and Credit Agreements for additional information on ExGen Renewables IV and ITEM 2.PROPERTIES for additional details on the specific projects included within EGRP.
Retail Power and Gas Companies
In March 2014, Generation began consolidating retail power and gas VIEs for which Generation is the primary beneficiary as a result, ComEd's electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer, or number of energy supply contracts that give Generation the powercustomers. ComEd is required to direct the activities that most significantly affect the economic performancefile an annual update to its electric distribution formula rate on or before May 1st, with resulting rates effective in January of the entities. Generation does not have an equity ownership interestfollowing year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in these entities, but provides approximately $34 million in credit supporteffect for the retail powerprior year and gas companiesactual costs incurred from the year (annual reconciliation).
ComEd’s 2020 approved revenue requirement above reflects an increase of $51 million for which Generation is the sole supplierinitial year revenue requirement for 2020 and a decrease of energy. These entities are included in Generation’s consolidated financial statements,$68 million related to the annual reconciliation for 2018. The revenue requirement for 2020 and the consolidationrevenue requirement for 2018 provides for a weighted average debt and equity return on distribution rate
CENG
CENG is a joint venture between Generation and EDF. On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the Nuclear Operating Services Agreement (NOSA) pursuant to which Generation now conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF. As a result of executing the NOSA, CENG qualifies as a VIE due to the disproportionate relationship between Generation’s 50.01% equity ownership interest and its role in conducting the operational activities of CENG and the CENG fleet conveyed through the NOSA. Further, since
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Generation is conductingbase of 6.51% inclusive of an allowed ROE of 8.91%, reflecting the operational activitiesmonthly average yields for 30-year treasury bonds plus 580 basis points.
ComEd’s 2021 approved revenue requirement above reflects an increase of CENG$50 million for the initial year revenue requirement for 2021 and a decrease of $64 million related to the annual reconciliation for 2019. The revenue requirement for 2021 and the CENG fleet, Generation qualifiesrevenue requirement for 2019 provide for a weighted average debt and equity return on distribution rate base of 6.28% inclusive of an allowed ROE of 8.38%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. See table below for ComEd's regulatory assets associated with its electric distribution formula rate.
(b) Reflects a three-year cumulative multi-year plan for 2021 through 2023. The MDPSC awarded BGE electric revenue requirement increases of $59 million, $39 million, and $42 million in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million in 2021, 2022, and 2023, respectively. However, the MDPSC utilized certain tax benefits to fully offset the increases in 2021 so that customer rates will remain unchanged from 2020 to 2021. The MDPSC has deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases in 2022 and 2023 and BGE cannot predict the outcome.
Pending Distribution Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant/Jurisdiction | | Filing Date | | Service | | Requested Revenue Requirement Increase | | Requested ROE | | Expected Approval Timing |
| | | | | | | | | | |
| PECO - Pennsylvania | | September 30, 2020 | | Natural Gas | | $ | 69 | | | 10.95 | % | | Second quarter of 2021 |
| | | | | | | | | | |
Pepco - District of Columbia(a) | | May 30, 2019 (amended June 1, 2020) | | Electric | | 136 | | | 9.7 | % | | Second quarter of 2021 |
Pepco - Maryland(b) | | October 26, 2020 | | Electric | | 110 | | | 10.2 | % | | Second quarter of 2021 |
DPL - Delaware(c) | | March 6, 2020 (amended February 2, 2021) | | Electric | | 23 | | | 10.3 | % | | Third quarter of 2021 |
ACE - New Jersey(d) | | December 9, 2020 | | Electric | | 67 | | | 10.3 | % | | Fourth quarter of 2021 |
_________
(a)Pepco filed the multi-year plan enhanced proposal as an alternative to address the primary beneficiaryimpacts of CENGCOVID-19. Reflects a three-year cumulative multi-year plan for 2020 through 2022 and therefore, is requiredrequested revenue requirement increases of $73 million in 2022 and $63 million in 2023, to consolidate the results of operationsrecover capital investments made during 2018 through 2020 and financial position of CENG.
Exelon and Generation, where indicated, provide the following support to CENG:
under power purchase agreements with CENG, Generation purchased or will purchase 50.01% of the available output generated by the CENG nuclear plants not subject to other contractual agreements from January 2015planned capital investments through the end of the operating life of each respective plant. However, pursuant to amendments dated2022.
(b)Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2015,2024 and total requested revenue requirement increases of $56 million effective April 1, 2023 and $54 million effective April 1, 2024 to recover capital investments made in 2019 and 2020 and planned capital investments through March 31, 2024.
(c)The rates went into effect on October 6, 2020, subject to refund.
(d)Requested increases are before New Jersey sales and use tax. ACE intends to put rates into effect on September 8, 2021, subject to refund.
Transmission Formula Rates(Exelon, PHI, and the energy obligations underUtility Registrants)
The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the Ginna Nuclear Power Plant (Ginna) PPAs were suspended duringFERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the termresulting rates effective on June 1 of the RSSA, throughsame year. The annual update for ComEd, BGE, DPL, and ACE is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for Pepco is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for ComEd, BGE, DPL, and ACE also reconciles any differences between the end of March 31, 2017. With the expirationrevenue requirement in effect beginning June 1 of the RSSA,prior year and actual costs incurred for that year (annual reconciliation). The update for PECO and Pepco also reconciles any differences between the PPA was reinstated beginning April 1, 2017. (see Note 4 — Regulatory Matters for additional details),
Generation provided a $400 million loan to CENG. As of December 31, 2018, the remaining obligation is $196 million, including accrued interest. The remaining balance was fully paid by CENG in January 2019.
Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 22 — Commitmentsactual costs and Contingencies for more details),
Generation and EDF share in the $688 million of contingent payment obligationsactual revenues for the paymentcalendar year (annual reconciliation).
Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.
As of December 31, 2018 and 2017, Exelon's, PHI's and ACE's consolidated VIE consists of:
ACE Transition Funding
A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of transition bonds. Proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. During the three years ended December 31, 2018, 2017 and 2016, ACE transferred $30 million, $48 million and $60 million to ATF, respectively.
As of December 31, 2018 and 2017, ComEd, PECO, BGE, Pepco and DPL do not have any material consolidated VIEs.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
AssetsFor 2020, the following total increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Registrant(a) | | Initial Revenue Requirement Increase/(Decrease) | | Annual Reconciliation Decrease | | Total Revenue Requirement Increase/(Decrease)(b) | | Allowed Return on Rate Base(c) | | Allowed ROE(d) |
| ComEd | | $ | 18 | | | $ | (4) | | | $ | 14 | | | 8.17 | % | | 11.50 | % |
| PECO | | 5 | | | (28) | | | (23) | | | 7.47 | % | | 10.35 | % |
| BGE | | 16 | | | (3) | | | 4 | | | 7.26 | % | | 10.50 | % |
| Pepco | | 2 | | | (46) | | | (44) | | | 7.81 | % | | 10.50 | % |
| DPL | | (4) | | | (40) | | | (44) | | | 7.20 | % | | 10.50 | % |
| ACE | | 5 | | | (25) | | | (20) | | | 7.40 | % | | 10.50 | % |
__________
(a)All rates are effective June 30, 2020 - May 31, 2021, subject to review by interested parties pursuant to review protocols of each Utility Registrant's tariff.
(b)The decrease in PECO's transmission revenue requirement relates to refunds from December 1, 2017, in accordance with the settlement agreement dated July 22, 2019. The increase in BGE's transmission revenue requirement includes a $9 million reduction related to a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE. ComEd, BGE, Pepco, DPL, and LiabilitiesACE’s transmission revenue requirement include a decrease related to the April 24, 2020 settlement agreement related to excess deferred income taxes. Refer to Transmission-Related Income Tax Regulatory assets below for additional information.
(c)Represents the weighted average debt and equity return on transmission rate bases.
(d)As part of Consolidated VIEs
Included within the balances above are assetsFERC-approved settlement of ComEd’s 2007 and liabilitiesPECO's 2017 transmission rate cases, the rate of certain consolidated VIEsreturn on common equity is 11.50% and 10.35%, respectively inclusive of a 50-basis-point incentive adder for whichbeing a member of a RTO, and the assets can only becommon equity component of the ratio used to settle obligations of those VIEs,calculate the weighted average debt and liabilities that creditors, or beneficiaries, do not have recourse toequity return for the general credittransmission formula rate is currently capped at 55% and 55.75%, respectively. As part of the Registrants. AsFERC-approved settlement of the ROE complaint against BGE, Pepco, DPL, and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.
Other State Regulatory Matters
Illinois Regulatory Matters
Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through the electric distribution formula rate) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018 through December 31, 2018 and 2017, these assets and liabilities primarily consisted2030, the ROE that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency formula rate on or before June 1st each year, with resulting rates effective in January of the following:following year. The annual update is based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions similar to those in ComEd’s electric distribution formula rate.
During 2020, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:
|
| | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | Exelon(a) | | Generation | | PHI(a) | | ACE |
| Cash and cash equivalents | $ | 414 |
| | $ | 414 |
| | $ | — |
| | $ | — |
|
| Restricted cash and cash equivalents | 66 |
| | 62 |
| | 4 |
| | 4 |
|
| Accounts receivable, net | | | | | | | |
| Customer | 146 |
| | 146 |
| | — |
| | — |
|
| Other | 23 |
| | 23 |
| | — |
| | — |
|
| Inventory | | | | | | | |
| Materials and supplies | 212 |
| | 212 |
| | — |
| | — |
|
| Other current assets | 52 |
| | 49 |
| | 3 |
| | — |
|
| Total current assets | 913 |
|
| 906 |
|
| 7 |
|
| 4 |
|
| | | | | | | | |
| Property, plant and equipment, net | 6,145 |
| | 6,145 |
| | — |
| | — |
|
| Nuclear decommissioning trust funds | 2,351 |
| | 2,351 |
| | — |
| | — |
|
| Other noncurrent assets | 258 |
| | 232 |
| | 26 |
| | 19 |
|
| Total noncurrent assets | 8,754 |
|
| 8,728 |
|
| 26 |
|
| 19 |
|
| Total assets | $ | 9,667 |
|
| $ | 9,634 |
|
| $ | 33 |
|
| $ | 23 |
|
| | | | | | | | |
| Long-term debt due within one year | $ | 87 |
| | $ | 66 |
| | $ | 21 |
| | $ | 18 |
|
| Accounts payable | 96 |
| | 96 |
| | — |
| | — |
|
| Accrued expenses | 72 |
| | 72 |
| | 1 |
| | 1 |
|
| Unamortized energy contract liabilities | 15 |
| | 15 |
| | — |
| | — |
|
| Other current liabilities | 3 |
| | 3 |
| | — |
| | — |
|
| Total current liabilities | 273 |
|
| 252 |
|
| 22 |
|
| 19 |
|
| | | | | | | | |
| Long-term debt | 1,072 |
| | 1,025 |
| | 47 |
| | 40 |
|
| Asset retirement obligations | 2,160 |
| | 2,160 |
| | — |
| | — |
|
| Unamortized energy contract liabilities | 1 |
| | 1 |
| | — |
| | — |
|
| Other noncurrent liabilities | 42 |
| | 42 |
| | — |
| | — |
|
| Total noncurrent liabilities | 3,275 |
|
| 3,228 |
|
| 47 |
|
| 40 |
|
| Total liabilities | $ | 3,548 |
|
| $ | 3,480 |
|
| $ | 69 |
|
| $ | 59 |
|
__________
| |
(a) | Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
|
| | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Exelon(a) | | Generation | | PHI(a) | | ACE |
| Cash and cash equivalents | $ | 126 |
| | $ | 126 |
| | $ | — |
| | $ | — |
|
| Restricted cash and cash equivalents | 64 |
| | 58 |
| | 6 |
| | 6 |
|
| Accounts receivable, net | | | | | | | |
| Customer | 170 |
| | 170 |
| | — |
| | — |
|
| Other | 25 |
| | 25 |
| | — |
| | — |
|
| Inventory | | | | | | | |
| Materials and supplies | 205 |
| | 205 |
| | — |
| | — |
|
| Other current assets | 45 |
| | 41 |
| | 4 |
| | — |
|
| Total current assets | 635 |
| | 625 |
| | 10 |
| | 6 |
|
| | | | | | | | |
| Property, plant and equipment, net | 6,186 |
| | 6,186 |
| | — |
| | — |
|
| Nuclear decommissioning trust funds | 2,502 |
| | 2,502 |
| | — |
| | — |
|
| Other noncurrent assets | 274 |
| | 243 |
| | 31 |
| | 23 |
|
| Total noncurrent assets | 8,962 |
| | 8,931 |
| | 31 |
| | 23 |
|
| Total assets | $ | 9,597 |
| | $ | 9,556 |
| | $ | 41 |
| | $ | 29 |
|
| | | | | | | | |
| Long-term debt due within one year | $ | 102 |
| | $ | 67 |
| | $ | 35 |
| | $ | 31 |
|
| Accounts payable | 114 |
| | 114 |
| | — |
| | — |
|
| Accrued expenses | 67 |
| | 66 |
| | 1 |
| | 1 |
|
| Unamortized energy contract liabilities | 18 |
| | 18 |
| | — |
| | — |
|
| Other current liabilities | 7 |
| | 7 |
| | — |
| | — |
|
| Total current liabilities | 308 |
| | 272 |
| | 36 |
| | 32 |
|
| | | | | | | | |
| Long-term debt | 1,154 |
| | 1,088 |
| | 66 |
| | 58 |
|
| Asset retirement obligations | 2,035 |
| | 2,035 |
| | — |
| | — |
|
| Other noncurrent liabilities | 121 |
| | 121 |
| | — |
| | — |
|
| Total noncurrent liabilities | 3,310 |
| | 3,244 |
| | 66 |
| | 58 |
|
| Total liabilities | $ | 3,618 |
| | $ | 3,516 |
| | $ | 102 |
| | $ | 90 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Filing Date | | Requested Revenue Requirement Increase | | Approved Revenue Requirement Increase | | Approved ROE | | Approval Date | | Rate Effective Date |
| May 21, 2020 | | $ | 48 | | | $ | 48 | | (a) | 8.38 | % | | December 2, 2020 | | January 1, 2021 |
__________
| |
(a) | Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity. |
Unconsolidated Variable Interest Entities_________
Exelon’s(a)ComEd’s 2021 approved revenue requirement above reflects an increase of $45 million for the initial year revenue requirement for 2021 and Generation’s variable interestsan increase of $3 million related to the annual reconciliation for 2019. The revenue requirement for 2021 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.28% inclusive of an allowed ROE of 8.38%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for 2019 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.56% inclusive of an allowed ROE of 8.96%, which includes an upward performance adjustment that can either increase or decrease the ROE. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate.
Maryland Regulatory Matters
The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). On December 1, 2017 (as amended on January 22, 2018), BGE filed an application with the MDPSC seeking approval for a new gas infrastructure replacement plan and associated surcharge, effective for the five-year period from 2019 through 2023. On May 30, 2018, the MDPSC approved with modifications a new infrastructure plan and associated surcharge, subject to BGE's acceptance of the Order. On June 1, 2018, BGE accepted the MDPSC Order and the associated surcharge became effective January 2019. The five-year plan calls for capital expenditures over the 2019-2023 timeframe of $732 million with an associated revenue requirement of $200 million.
Cash Working Capital Order (Exelon and BGE). On November 17, 2016, the MDPSC rendered a decision in unconsolidated VIEs generally include equity investmentsthe proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its POLR service, also known as SOS, as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover its SOS-related costs. The Administrative Charge is comprised of five components: CWC, uncollectibles, incremental costs, return, and energy purchasean administrative adjustment, which acts as a proxy for retail suppliers’ costs. The MDPSC accepted BGE's positions on recovery of CWC and sale contracts. Forpass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a return on the equity investments,SOS. Subsequently, the carryingMDPSC Staff and residential consumer advocate sought clarification and appealed the amount of return awarded to BGE on the investments is reflectedSOS. On July 27, 2020, the Maryland Court of Special Appeals affirmed the circuit court’s judgment affirming the MDPSC’s decision. No party appealed the decision to the Maryland Court of Appeals. Also, in Exelon’sBGE’s 2019 electric and Generation’s Consolidated Balance Sheets in Investments. Forgas distribution base rate proceeding, the energy purchaseMDPSC established a normalized administrative adjustment. However, a group of electric suppliers appealed the MDPSC’s decision to the Circuit Court for Baltimore City. BGE cannot predict the outcome of this appeal.
New Jersey Regulatory Matters
ACE Infrastructure Investment Program Filing (Exelon, PHI, and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvementACE). On February 28, 2018, ACE filed with the VIEs are predominatelyNJBPU the company’s IIP proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $96 million of reliability related to working capital accountsinvestments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement.
Advanced Metering Infrastructure Filing (Exelon, PHI, and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associatedACE). On August 26, 2020, ACE filed an application with the current billing cycles underNJBPU as was required seeking approval to deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consists of estimated costs totaling $220 million, with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that involves the commercial agreements. Further, Exeloninstallation of an integrated system of smart meters for all customers accompanied by the requisite communications facilities and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated withdata management systems. ACE is seeking authority to recover these commercial agreements.
Asestimated investments through a combination of December 31, 2018the ACE IIP rider mechanism and 2017, Exelon and Generation had significant unconsolidated variable interestsfuture distribution base rates. ACE currently expects a decision in seven VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements. Exelon and Generation only include unconsolidated VIEs that are individually materialthis matter in the tables below. However, Exelon and Generation have several individually immaterial VIEs that in aggregate represent a total investmentthird quarter of $15 million and $13 million, respectively,2021 but cannot predict if the NJBPU will approve the application as filed.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
as of December 31, 2018. These immaterial VIEs are equityNew Jersey Clean Energy Legislation (Exelon, PHI, and debt securities inACE).On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey’s clean energy development companies. As of December 31, 2018,and energy efficiency programs and solar and RPS. On the maximum exposure to loss related to these securities included in Investments in Exelon's and Generation's Consolidated Balance Sheets is limitedsame day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the $15 millionNJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and $13 million, respectively.
The following tables present summary information about Exelonthat their revenues are insufficient to cover their costs and Generation’s significant unconsolidated VIE entities:
|
| | | | | | | | | | | |
| December 31, 2018 | Commercial Agreement VIEs | | Equity Investment VIEs | | Total |
Total assets(a) | $ | 597 |
| | $ | 472 |
| | $ | 1,069 |
|
Total liabilities(a) | 37 |
| | 222 |
| | 259 |
|
Exelon's ownership interest in VIE(a) | — |
| | 223 |
| | 223 |
|
Other ownership interests in VIE(a) | 560 |
| | 27 |
| | 587 |
|
| Registrants’ maximum exposure to loss: | | | | |
|
|
| Carrying amount of equity method investments | — |
| | 223 |
| | 223 |
|
| Contract intangible asset | 7 |
| | — |
| | 7 |
|
Net assets pledged for Zion Station decommissioning(b) | — |
| | — |
| | — |
|
|
| | | | | | | | | | | |
| December 31, 2017 | Commercial Agreement VIEs | | Equity Investment VIEs | | Total |
Total assets(a) | $ | 625 |
| | $ | 509 |
| | $ | 1,134 |
|
Total liabilities(a) | 37 |
| | 228 |
| | 265 |
|
Exelon's ownership interest in VIE(a) | — |
| | 251 |
| | 251 |
|
Other ownership interests in VIE(a) | 588 |
| | 30 |
| | 618 |
|
| Registrants’ maximum exposure to loss: | | | | |
|
|
| Carrying amount of equity method investments | — |
| | 251 |
| | 251 |
|
| Contract intangible asset | 8 |
| | — |
| | 8 |
|
Net assets pledged for Zion Station decommissioning(b) | 2 |
| | — |
| | 2 |
|
__________
| |
(a) | These items represent amounts on the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. |
| |
(b) | These items represent amounts in Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $9 million and $39 million as of December 31, 2018 and December 31, 2017, respectively; offset by payables to ZionSolutions LLC of $9 million and $37 million as of December 31, 2018 and December 31, 2017, respectively. These items are included to provide information regarding the relative size of the ZionSolutions, LLC unconsolidated VIE. |
For eachrisks. Electric distribution utilities in New Jersey, including ACE, began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the utility’s procurement of the unconsolidated VIEs, ExelonZECs effective April 18, 2019. See Generation Regulatory Matters below for additional information.
Other Federal Regulatory Matters
Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL, and GenerationACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have assessedbeen previously amortized and (2) amounts that would be amortized and recovered prospectively. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. In the riskfourth quarter of a loss equal to2017, ComEd, BGE, Pepco, DPL, and ACE fully impaired their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with anytransmission-related income tax regulatory assets for the portion of the maximum exposure to loss. In addition, there are no material agreements with, or commitments by, third partiesincome tax regulatory assets that would materially affecthave been previously amortized.
On February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the fair value or risktransmission formula rate provided for such recovery.
On September 7, 2018, FERC issued orders rejecting 1) BGE’s rehearing request of FERC's November 16, 2017 order and 2) the February 23, 2018 (as amended on July 9, 2018) filing by ComEd, Pepco, DPL, and ACE for similar recovery.
On November 2, 2018, BGE filed an appeal of FERC's September 7, 2018 order to the U.S. Court of Appeals for the D.C. Circuit. On March 27, 2020, the U.S. Court of Appeals for the D.C. Circuit Court denied BGE’s November 2, 2018 appeal.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and credit TCJA transmission-related income tax regulatory liabilities to customers for the prospective period starting on October 1, 2018. On April 26, 2019, FERC issued an order accepting ComEd's, BGE's, Pepco's, DPL's, and ACE's October 1, 2018 filings, effective October 1, 2018, subject to refund and established hearing and settlement judge procedures. On April 24, 2020, ComEd, BGE, Pepco, DPL, ACE, and other parties filed a settlement agreement with FERC, which FERC approved on September 24, 2020. The settlement agreement provides for the recovery of ongoing transmission-related income tax regulatory assets and establishes the amount and amortization period for excess deferred income taxes resulting from TCJA. The settlement resulted in a reduction to Operating revenues and an offsetting reduction to Income tax expense in the second quarter of 2020.
Regulatory Assets and Liabilities
Regulatory assets represent incurred costs that have been deferred because of their variable interestsprobable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in these VIEs.advance of expenditures for approved regulatory programs.
Energy Purchase and Sale Agreements
Generation has several energy purchase and sale agreements with generating facilities. Generation has evaluated the significant agreements, ownership structures and risks of each entity, and determined that certain of the entities are VIEs because the entity absorbs risk through the sale of fixed price power and renewable energy credits. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the VIEs
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
because Generation does not haveThe following tables provide information about the power to direct the activities that most significantly impact the VIEs economic performance.
ZionSolutions
Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 15 — Asset Retirement Obligations. Under this agreement, ZionSolutions can put theregulatory assets and liabilities backof Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE as of December 31, 2020 and December 31, 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory assets | | | | | | | | | | | | | | | |
| Pension and OPEB | $ | 3,010 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Pension and OPEB - merger related | 1,014 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred income taxes | 715 | | | 0 | | | 705 | | | 0 | | | 10 | | | 10 | | | 0 | | | 0 | |
| AMI programs - deployment costs | 174 | | | 0 | | | 0 | | | 109 | | | 65 | | | 35 | | | 30 | | | 0 | |
| AMI programs - legacy meters | 219 | | | 90 | | | 0 | | | 37 | | | 92 | | | 68 | | | 24 | | | 0 | |
| | | | | | | | | | | | | | | |
| Electric distribution formula rate annual reconciliations | (14) | | | (14) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Electric distribution formula rate significant one-time events | 117 | | | 117 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Energy efficiency costs | 982 | | | 982 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Fair value of long-term debt | 598 | | | 0 | | | 0 | | | 0 | | | 478 | | | 0 | | | 0 | | | 0 | |
| Fair value of PHI's unamortized energy contracts | 328 | | | 0 | | | 0 | | | 0 | | | 328 | | | 0 | | | 0 | | | 0 | |
| Asset retirement obligations | 135 | | | 92 | | | 21 | | | 18 | | | 4 | | | 3 | | | 0 | | | 1 | |
| MGP remediation costs | 285 | | | 271 | | | 10 | | | 4 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Renewable energy | 301 | | | 301 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Electric energy and natural gas costs | 95 | | | 0 | | | 0 | | | 23 | | | 72 | | | 37 | | | 5 | | | 30 | |
| Transmission formula rate annual reconciliations | 5 | | | 0 | | | 0 | | | 2 | | | 3 | | | 0 | | | 2 | | | 1 | |
| Energy efficiency and demand response programs | 572 | | | 0 | | | 0 | | | 289 | | | 283 | | | 203 | | | 80 | | | 0 | |
| | | | | | | | | | | | | | | |
| Under-recovered revenue decoupling | 113 | | | 0 | | | 0 | | | 20 | | | 93 | | | 93 | | | 0 | | | 0 | |
| Stranded costs | 25 | | | 0 | | | 0 | | | 0 | | | 25 | | | 0 | | | 0 | | | 25 | |
| Removal costs | 701 | | | 0 | | | 0 | | | 107 | | | 594 | | | 151 | | | 105 | | | 339 | |
| DC PLUG charge | 100 | | | 0 | | | 0 | | | 0 | | | 100 | | | 100 | | | 0 | | | 0 | |
| Deferred storm costs | 50 | | | 0 | | | 0 | | | 0 | | | 50 | | | 5 | | | 4 | | | 41 | |
| COVID-19 | 81 | | | 22 | | | 38 | | | 10 | | | 11 | | | 7 | | | 4 | | | 0 | |
| Under-recovered credit loss expense | 107 | | | 89 | | | 0 | | | 0 | | | 18 | | | 0 | | | 0 | | | 18 | |
| Other | 274 | | | 78 | | | 27 | | | 30 | | | 147 | | | 72 | | | 26 | | | 15 | |
| Total regulatory assets | 9,987 | | | 2,028 | | | 801 | | | 649 | | | 2,373 | | | 784 | | | 280 | | | 470 | |
| Less: current portion | 1,228 | | | 279 | | | 25 | | | 168 | | | 440 | | | 214 | | | 58 | | | 75 | |
| Total noncurrent regulatory assets | $ | 8,759 | | | $ | 1,749 | | | $ | 776 | | | $ | 481 | | | $ | 1,933 | | | $ | 570 | | | $ | 222 | | | $ | 395 | |
Combined Notes to Generation when decommissioning activities under the asset sale agreement are complete. Generation has evaluated this agreement and determined that, through the put option, it has a variable interestConsolidated Financial Statements
(Dollars in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required. Other than the asset sale agreement, Exelon and Generation do not have any contractual or other obligationsmillions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory liabilities | | | | | | | | | | | | | | | |
| Deferred income taxes | $ | 4,502 | | | $ | 2,205 | | | $ | 0 | | | $ | 1,001 | | | $ | 1,296 | | | $ | 621 | | | $ | 404 | | | $ | 271 | |
| Nuclear decommissioning | 3,016 | | | 2,541 | | | 475 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Removal costs | 1,649 | | | 1,482 | | | 0 | | | 47 | | | 120 | | | 20 | | | 100 | | | 0 | |
| Electric energy and natural gas costs | 175 | | | 34 | | | 97 | | | 6 | | | 38 | | | 24 | | | 10 | | | 4 | |
| Transmission formula rate annual reconciliations | 52 | | | 2 | | | 12 | | | 0 | | | 38 | | | 23 | | | 9 | | | 6 | |
| Renewable portfolio standards costs | 427 | | | 427 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Stranded costs | 24 | | | 0 | | | 0 | | | 0 | | | 24 | | | 0 | | | 0 | | | 24 | |
| Other | 221 | | | 1 | | | 40 | | | 85 | | | 59 | | | 2 | | | 17 | | | 13 | |
| Total regulatory liabilities | 10,066 | | | 6,692 | | | 624 | | | 1,139 | | | 1,575 | | | 690 | | | 540 | | | 318 | |
| Less: current portion | 581 | | | 289 | | | 121 | | | 30 | | | 137 | | | 46 | | | 47 | | | 44 | |
| Total noncurrent regulatory liabilities | $ | 9,485 | | | $ | 6,403 | | | $ | 503 | | | $ | 1,109 | | | $ | 1,438 | | | $ | 644 | | | $ | 493 | | | $ | 274 | |
Combined Notes to provide additional financial support and ZionSolutions’ creditors do not have any recourseConsolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2019 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory assets | | | | | | | | | | | | | | | |
| Pension and OPEB | $ | 2,784 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | — | | | $ | 0 | | | $ | 0 | |
| Pension and OPEB - merger related | 1,138 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred income taxes | 528 | | | 0 | | | 518 | | | 0 | | | 10 | | | 10 | | | 0 | | | 0 | |
| AMI programs - deployment costs | 207 | | | 0 | | | 0 | | | 129 | | | 78 | | | 43 | | | 35 | | | 0 | |
| AMI programs - legacy meters | 276 | | | 113 | | | 12 | | | 45 | | | 106 | | | 79 | | | 27 | | | 0 | |
| Electric distribution formula rate annual reconciliations | 34 | | | 34 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Electric distribution formula rate significant one-time events | 66 | | | 66 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Energy efficiency costs | 746 | | | 746 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Fair value of long-term debt | 650 | | | 0 | | | 0 | | | 0 | | | 523 | | | 0 | | | 0 | | | 0 | |
| Fair value of PHI's unamortized energy contracts | 443 | | | 0 | | | 0 | | | 0 | | | 443 | | | 0 | | | 0 | | | 0 | |
| Asset retirement obligations | 127 | | | 85 | | | 23 | | | 16 | | | 3 | | | 2 | | | 0 | | | 1 | |
| MGP remediation costs | 302 | | | 287 | | | 11 | | | 4 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Renewable energy | 301 | | | 301 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Electric energy and natural gas costs | 110 | | | 0 | | | 6 | | | 36 | | | 68 | | | 43 | | | 5 | | | 20 | |
| Transmission formula rate annual reconciliations | 11 | | | 0 | | | 0 | | | 1 | | | 10 | | | 1 | | | 2 | | | 7 | |
| Energy efficiency and demand response programs | 572 | | | 0 | | | 0 | | | 303 | | | 269 | | | 196 | | | 73 | | | 0 | |
| Merger integration costs | 32 | | | 0 | | | 0 | | | 2 | | | 30 | | | 15 | | | 8 | | | 7 | |
| Under-recovered revenue decoupling | 37 | | | 0 | | | 0 | | | 8 | | | 29 | | | 29 | | | 0 | | | 0 | |
| Stranded costs | 37 | | | 0 | | | 0 | | | 0 | | | 37 | | | 0 | | | 0 | | | 37 | |
| Removal costs | 641 | | | 0 | | | 0 | | | 67 | | | 574 | | | 152 | | | 100 | | | 324 | |
| DC PLUG charge | 126 | | | 0 | | | 0 | | | 0 | | | 126 | | | 126 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | |
| Other | 337 | | | 129 | | | 25 | | | 26 | | | 167 | | | 76 | | | 24 | | | 29 | |
| Total regulatory assets | 9,505 | | | 1,761 | | | 595 | | | 637 | | | 2,473 | | | 772 | | | 274 | | | 425 | |
| Less: current portion | 1,170 | | | 281 | | | 41 | | | 183 | | | 412 | | | 188 | | | 52 | | | 57 | |
| Total noncurrent regulatory assets | $ | 8,335 | | | $ | 1,480 | | | $ | 554 | | | $ | 454 | | | $ | 2,061 | | | $ | 584 | | | $ | 222 | | | $ | 368 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2019 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory liabilities | | | | | | | | | | | | | | | |
| Deferred income taxes | $ | 4,944 | | | $ | 2,297 | | | $ | 0 | | | $ | 1,089 | | | $ | 1,558 | | | $ | 725 | | | $ | 477 | | | $ | 356 | |
| Nuclear decommissioning | 3,102 | | | 2,622 | | | 480 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Removal costs | 1,621 | | | 1,435 | | | 0 | | | 58 | | | 128 | | | 20 | | | 108 | | | 0 | |
| | | | | | | | | | | | | | | |
| Electric energy and natural gas costs | 109 | | | 45 | | | 56 | | | 0 | | | 8 | | | 0 | | | 8 | | | 0 | |
| Transmission formula rate annual reconciliations | 34 | | | 6 | | | 28 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | |
| Other | 582 | | | 337 | | | 37 | | | 81 | | | 83 | | | 9 | | | 18 | | | 26 | |
| Total regulatory liabilities | 10,392 | | | 6,742 | | | 601 | | | 1,228 | | | 1,777 | | | 754 | | | 611 | | | 382 | |
| Less: current portion | 406 | | | 200 | | | 91 | | | 33 | | | 70 | | | 8 | | | 37 | | | 25 | |
| Total noncurrent regulatory liabilities | $ | 9,986 | | | $ | 6,542 | | | $ | 510 | | | $ | 1,195 | | | $ | 1,707 | | | $ | 746 | | | $ | 574 | | | $ | 357 | |
Combined Notes to Exelon’s or Generation’s general credit.Consolidated Financial Statements
Investment(Dollars in Distributed Energy Companiesmillions, except per share data unless otherwise noted)
In July 2014, Generation entered into an arrangement to purchase a 90% equity interest and 90%
Note 3 — Regulatory Matters
Descriptions of the tax attributesregulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
| Pension and OPEB | Primarily reflects the Utility Registrants' portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and OPEB plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets. | The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. See Note 15 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. | No |
| Pension and OPEB - merger related | The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. See Note 15 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. | Legacy Constellation - 2038 Legacy PHI - 2032 | No |
| Deferred income taxes | Deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA. These amounts include transmission-related regulatory liabilities that require FERC approval separate from the transmission formula rate. See Transmission-Related Income Tax Regulatory Assets section above for additional information. | Over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules. | No |
| | | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
AMI programs - deployment costs
| Installation costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters. | BGE - 2026 Pepco - 2027 DPL - 2030 | Yes |
| AMI programs - legacy meters | Early retirement costs of legacy meters. | ComEd - 2028 BGE - 2026 Pepco - 2027 DPL - 2030 | ComEd, Pepco (District of Columbia), DPL (Delaware) - Yes BGE, Pepco (Maryland), DPL (Maryland) - No |
Electric distribution formula rate annual reconciliations
| Under/(Over)-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which is updated annually with rates effective on January 1st. | 2022
| Yes |
| Electric distribution formula rate significant one-time events | Deferred distribution service costs related to ComEd's significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event. | 2024 | Yes |
Energy efficiency costs
| ComEd's costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure. | 2031 | Yes
|
Fair value of long-term debt
| Represents the difference between the carrying value and fair value of long-term debt of PHI and BGE of $478 million and $120 million, respectively, as of December 31, 2020 and $523 million and $127 million, respectively, as of December 31, 2019, as of the PHI and Constellation merger dates. | BGE - 2036
PHI - 2045 | No |
Fair value of PHI’s unamortized energy contracts
| Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's, and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date. | 2036 | No |
| Asset retirement obligations | Future legally required removal costs associated with existing AROs. | Over the life of the related assets. | Yes, once the removal activities have been performed. |
MGP remediation costs
| Environmental remediation costs for MGP sites recorded at ComEd, PECO, and BGE.
| Over the expected remediation period. See Note 19 — Commitments and Contingencies for additional information. | No |
| | | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
| Renewable energy | Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts. | 2032 | No |
| Electric energy and natural gas costs | Under (over)-recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders. | 2025 | DPL (Delaware), ACE - Yes ComEd, PECO, BGE, Pepco, DPL (Maryland) - No |
| Transmission formula rate annual reconciliations | Under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants’ FERC formula rates, which are updated annually with rates effective each June 1st. | 2022 | Yes |
| Energy efficiency and demand response programs | Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers. | PECO - 2021 BGE - 2025 Pepco, DPL - 2035 | BGE, Pepco, DPL - Yes PECO - Yes on capital investment recovered through this mechanism |
| Merger integration costs | Integration costs to achieve distribution synergies related to the Constellation merger and PHI acquisition. Costs for Pepco (Maryland) and Pepco (District of Columbia) were $3 million and $9 million, respectively as of December 31, 2020, which are included in Other in the table above, and $6 million and $9 million, respectively as of December 31, 2019. | BGE - 2021 Pepco - 2021 DPL- 2026 ACE - 2022 | BGE, Pepco (Maryland), DPL - Yes
Pepco (District of Columbia), ACE - No |
Under (over)-recovered revenue decoupling
| Electric and / or gas distribution costs recoverable from or (refundable) to customers under decoupling mechanisms. | BGE and DPL - 2021 Pepco (Maryland) - $16 million - 2021 Pepco (District of Columbia) - $31 million - 2021; $46 million to be determined by the DCPSC | BGE, Pepco, DPL - No |
Stranded costs
| The regulatory asset represents certain stranded costs associated with ACE's former electricity generation business. The regulatory liability represents overcollection of a customer surcharge collected by ACE to fund principal and interest payments on Transition Bonds of ACE Transition Funding that securitized such costs. | Stranded costs - 2022
Overcollection - To be determined by NJBPU | Stranded costs - Yes
Overcollection - No |
| | | |
Combined Notes to a limited partnershipConsolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
Removal costs
| For BGE, Pepco, DPL, and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, Pepco, and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes. | BGE, Pepco, DPL, and ACE - Asset is generally recovered over the life of the underlying assets.
ComEd, BGE, Pepco, and DPL - Liability is reduced as costs are incurred. | Yes |
DC PLUG charge
| Costs associated with DC PLUG, which is a projected six year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia. Rates for the DC PLUG initiative went into effect on February 7, 2018. | 2021 - $30 million $70 million to be determined based on future biennial plans filed with the DCPSC. | Portion of asset funded by Pepco-Yes
|
| Deferred storm costs | For Pepco, DPL, and ACE amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland and New Jersey jurisdictions. | Pepco - 2024
DPL - $2 million - 2025; $2 million not currently being recovered
ACE - $5 million - 2021; $36 million not currently being recovered | Pepco, DPL - Yes
ACE - No |
Nuclear decommissioning
| Estimated future decommissioning costs for the Regulatory Agreement Units that are less than the associated NDT fund assets. See Note 10 — Asset Retirement Obligations for additional information. | Not currently being refunded.
| No |
| COVID-19 | See COVID-19 section below for detail on the COVID-19 regulatory asset. | ComEd - 2024
BGE - 2025
PECO, Pepco, DPL, and ACE - Not currently being recovered. | ComEd and BGE - Yes
PECO, Pepco, DPL, and ACE - No |
| | | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
| Under (over) -recovered credit loss expense | For ComEd and ACE, amounts represent the difference between annual credit loss expense and revenues collected in rates through ICC and NJBPU-approved riders. The difference between net credit loss expense and revenues collected through the rider each calendar year for ComEd is recovered or refunded over a twelve-month period beginning in June of the following calendar year. ACE intends to recover/refund from June through May of each respective year, subject to approval of the NJBPU. | ComEd - 2023
ACE - To be determined by NJBPU. | No |
| Renewable portfolio standards costs | Represents an overcollection of funds from both ComEd customers and alternative retail electricity suppliers to be spent on future renewable energy procurements. Costs were $320 million as of December 31, 2019, which are included in Other in the 2019 table above. | To be determined by the IPA and ICC. | No |
COVID-19 (Exelon and the limited partners do not have kick-out rightsUtility Registrants). Starting in March of 2020, the general partner. Generation is not the primary beneficiary; therefore, the investment continuesUtility Registrants temporarily suspended customer disconnections for non-payment and temporarily ceased new late payment fees for all customers and restored service to be recorded using the equity method.
During 2015, a company that is consolidated by Generation as a VIE entered into an arrangement to purchase a 90% equity interest and 99% of the tax attributes of another distributed energy company (see additional detailscustomers upon request who were disconnected in the Consolidated Variable Interest Entities section above).last twelve months. The equity holders (of which Generation is one) contributedduration and extent of these measures varies by jurisdiction. While these measures are no longer in place for some jurisdictions as of December 31, 2020, they are expected to the distributed energy company a total of $227 million of equity in proportion to their ownership interests. The equity holders provided a parental guarantee of up to $275 million in support of equity contributions to the distributed energy company. As all equity contributions were made as ofcontinue through the first quarter of 2021 in other jurisdictions. Typically, the Utility Registrants recover credit loss expense through regulatory required programs or distribution base rate cases. ComEd and ACE have existing mechanisms for recovery of credit loss expense. For those jurisdictions without an existing regulatory required program to recover credit loss expense, the Utility Registrants are pursuing strategies to recover incremental costs being incurred as a result of COVID-19:
•In the period of April to July of 2020, the MDPSC, the DCPSC, the DPSC, and the NJBPU issued orders authorizing the creation of regulatory assets to track incremental COVID-19 related costs.
•In May of 2020, the PAPUC issued a Secretarial Letter authorizing the creation of regulatory assets to track incremental credit loss expense related to COVID-19.
The Utility Registrants have also incurred direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of their employees.
The Utility Registrants have recorded regulatory assets for the impacts of COVID-19 reflecting primarily incremental credit losses and direct costs, partially offset by a decrease in travel costs at BGE and PHI. Refer to the Regulatory assets table above for amounts as of December 31, 2020. The Utility Registrants expect to seek recovery in upcoming distribution base rate cases.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Capitalized Ratemaking Amounts Not Recognized
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | ComEd(a) | | PECO | | BGE(b) | | PHI | | Pepco(c) | | DPL(c) | | ACE |
| December 31, 2020 | $ | 51 | | | $ | (1) | | | $ | 0 | | | $ | 45 | | | $ | 7 | | | $ | 4 | | | $ | 3 | | | $ | 0 | |
| December 31, 2019 | $ | 63 | | | $ | 3 | | | $ | 0 | | | $ | 53 | | | $ | 7 | | | $ | 4 | | | $ | 3 | | | $ | 0 | |
__________
(a)Reflects ComEd's unrecognized equity returns/(losses) earned/(incurred) for ratemaking purposes on its electric distribution formula rate regulatory assets.
(b)BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.
(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.
Generation Regulatory Matters (Exelon and Generation)
Illinois Regulatory Matters
Zero Emission Standard.Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1, and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event.
Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue with compensation for the sale of ZECs retroactive to the June 1, 2017 thereeffective date of FEJA. The ZEC price was initially established at $16.50 per MWh of production, subject to annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices. Illinois utilities are required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017 to May 31, 2018, and subsequent delivery year, June 1, 2018 to May 31, 2019, the ZEC annual cost cap was set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. During the first quarter of 2018, Generation recognized $150 million of revenue related to ZECs generated from June 1, 2017 through December 31, 2017.
New Jersey Regulatory Matters
New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $69 million and $53 million for the year ended December 31, 2020 and 2019, respectively. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU's decision to the New Jersey Superior Court. Briefing has been completed, and on December 9, 2020, oral argument took place. On October 1, 2020, PSEG and Generation filed applications seeking ZECs for the second eligibility period (June 2022 through May 2025). The NJBPU will act on the applications by the end of April 2021. Exelon and Generation cannot predict the outcome of the appeal. See Note 7 - Early Plant Retirements for additional information related to Salem.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
New York Regulatory Matters
New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which is a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC to be Generation's FitzPatrick, Ginna, and Nine Mile Point nuclear facilities.
On November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. On October 8, 2019, the court dismissed all remaining claims. The petitioners filed a notice of appeal on November 4, 2019 and originally had until May 4, 2020 to file their brief. Due to COVID-19 related restrictions, the court extended the deadline to July 29, 2020. Petitioners did not file a brief by the deadline, so the case is deemed dismissed. Petitioners are permitted up to one year from July 29, 2020 to file a motion to vacate the dismissal if they can show good cause for the delay.
See Note 7 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point.
New England Regulatory Matters
Mystic Units 8 & 9 and Everett Marine Terminal Cost of Service Agreement (Exelon and Generation). On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 & 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service compensation, reflecting a number of adjustments to the annual fixed revenue requirement, and allowing for recovery of a substantial portion of the costs associated with the adjacent Everett Marine Terminal acquired by Generation in October 2018. Those adjustments were reflected in a compliance filing made on March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. On January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings in the order.
On July 17, 2020, FERC issued three orders, which together affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of the Everett Marine Terminal. FERC directed a downward adjustment to the rate base for Mystic Units 8 and 9, the effect of which will be partially offset by elimination of a crediting mechanism for third party gas sales during the term of the cost of service agreement. A compliance filing was submitted on September 15, 2020 and is pending. Several parties filed protests to the compliance filing on the issue of how gross plant in-service was calculated and Generation filed an answer to the protests on October 21, 2020. On July 28, 2020, FERC ordered additional briefings in the ROE proceeding. On December 21, 2020, FERC issued an order on rehearing of the three July 17, 2020 orders, clarifying several cost of service provisions.
On August 25, 2020, a group of New England generators filed a complaint against Generation seeking to extend the scope of the claw back provision in the cost-of-service agreement, whereby Generation would refund certain amounts recovered during the term of the cost of service if it returns to market afterwards. On September 14, 2020, Generation filed an answer to the complaint arguing that the complaint is procedurally improper and a collateral attack on existing FERC orders, and pointing out that the ISO-NE tariff contains protections against the New England generators' concerns that they failed to mention. On September 28, 2020, New England generators filed an answer to Generation’s answer. Generation cannot predict the outcome of this proceeding.
On June 10, 2020, Generation filed a complaint with FERC against ISO-NE on the grounds that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic for transmission security for the 2024 to 2025 Capacity Commitment Period (FCA 15) and that the modifications that ISO-NE made to its unfiled planning procedures to avoid retaining Mystic should have been filed with FERC for approval. On July 27, 2020, ISO-NE issued a memo to NEPOOL announcing its determination pursuant to its unfiled planning procedures that Mystic Units 8 and 9 are not needed for FCA 15 for transmission security. It had previously determined Mystic Units 8 and 9 are not needed for fuel security. On August 17, 2020, FERC issued an order denying the complaint. On September 16,
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
2020, Generation filed a request for rehearing with FERC. On October 19, 2020, FERC denied rehearing by operation of law and on December 18, 2020, Generation appealed to the U.S. Court of Appeals for the D.C. Circuit. The timing and the outcome of this proceeding is uncertain.
See Note 7 — Early Plant Retirements and Note 12 — Asset Impairments for additional information on the impacts of Generation’s August 2020 decision to retire Mystic Units 8 & 9 upon expiration of the cost of service agreement.
Federal Regulatory Matters
PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a MOPR. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a state government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the MOPR in NYISO applies only to certain resources in downstate New York.
For Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation, an expanded MOPR would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions.
On December 19, 2019, FERC required PJM to broadly apply the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage, and all resources owned by vertically-integrated utilities. This greatly expands the breadth and scope of PJM’s MOPR, which is effective as of PJM’s next capacity auction. While FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources.
FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism (under which an entire utility zone would be removed from PJM’s capacity auction along with sufficient resources to support the load in such zone). In response to FERC’s order, PJM submitted a compliance filing on March 18, 2020 wherein PJM proposed tariff language interpreting and implementing FERC's directives, and proposed a schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing.
On April 16, 2020, FERC issued an order largely denying most requests for rehearing of FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing which PJM submitted on June 1, 2020.
On October 15, 2020, FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting PJM’s two compliance filings, subject to a further payment obligationcompliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, FERC also accepted PJM’s proposal to condense the schedule of activities leading up to the next capacity auction. In November 2020, PJM announced that it will conduct its next capacity auction beginning on May 19, 2021 and ending on May 25, 2021 and will post the results on June 2, 2021.
Because neither Illinois nor New Jersey have implemented an FRR program in their PJM zones, the MOPR will apply in that next capacity auction to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the parental guarantee. The distributed energy company meetsIllinois ZES, or the definitionNew Jersey ZEC program, as applicable, increasing the risk that those units may not clear the capacity market.
Exelon is currently working with PJM and other stakeholders to pursue the FRR option as an alternative to the PJM capacity auction. If Illinois implements the FRR option, Generation’s Illinois nuclear plants could be removed from PJM’s capacity auction and instead supply capacity, and be compensated under the FRR program, which has the potential to mitigate the current economic distress being experienced by Generation's nuclear plants in Illinois, as discussed in Note 7 — Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative and regulatory changes. Whether legislation is needed in New Jersey would depend on how the state chooses to structure an FRR program. Exelon cannot predict whether or when such legislative and regulatory changes can be implemented.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
On February 20, 2020, FERC issued an order rejecting requests to expand NYISO’s version of the MOPR (referred to as buyer-side mitigation rules) beyond its current limited applicability to certain resources in downstate. However, on October 14, 2020, two natural gas-fired generators in New York filed a VIE becausecomplaint at FERC seeking to expand the companyMOPR in NYISO to apply to all resources, new and existing, across the entire NYISO market. Exelon is strenuously opposing expansion of FERC’s MOPR policies in the NYISO market. While it is too early in the proceeding to predict its outcome and there are significant differences between the NYISO and PJM markets that would justify a different result, if FERC follows its MOPR precedent in PJM and applies the MOPR in NYISO broadly as requested in the complaint, Generation’s facilities in NYISO that are receiving ZEC compensation may be at increased risk of not clearing the capacity auction.
If Generation’s state-supported nuclear plants in PJM or NYISO are subjected to the MOPR or equivalent without compensation under an FRR or similar program, it could have a material adverse impact on Exelon's and Generation's financial statements, which Exelon and Generation cannot reasonably estimate at this time.
Operating License Renewals
Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, Generation has a similar structurebeen working with MDE and other stakeholders to a limited partnershipresolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.
On April 21, 2016, Generation and the limited partners do not have kick-out rightsU.S. Fish and Wildlife Service of the general partner. Generation is notU.S. Department of the primary beneficiary; therefore,Interior executed a settlement agreement (DOI Settlement) resolving all fish passage issues between the investment is recorded usingparties.
On April 27, 2018, MDE issued its 401 Certification for Conowingo. As issued, the equity method.
Both distributed energy companies401 Certification contains numerous conditions, including those relating to reduction of nutrients from the 2015upstream sources, removal of all visible trash and 2014 arrangements are considered related partiesdebris from upstream sources, and implementation of measures relating to Generation.
ComEd and PECO
The financing trust of ComEd, ComEd Financing III, and the financing trusts of PECO, PECO Trust III and PECO Trust IV, are not consolidated in Exelon’s, ComEd’s, or PECO’s financial statements. These financing trusts were created to issue mandatorily redeemable trust preferred securities. ComEd and PECO have concluded that they do notfish passage, which could have a significant variable interestmaterial, unfavorable impact on Exelon’s and Generation’s financial statements through an increase in ComEd Financing III, PECO Trust III, or PECO Trust IV as each Registrant financed its equity interestcapital expenditures and operating costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the financing trusts throughconditions are unfair and onerous and in violation of MDE regulations and state, federal, and constitutional law. Generation also requested that FERC defer the issuance of subordinated debtthe federal license while these significant state and therefore, has no equity at risk.federal law issues are pending. On February 28, 2019, Generation filed a Petition for Declaratory Order with FERC requesting that FERC issue an order declaring that MDE waived its right to issue a 401 Certification for Conowingo because it failed to timely act on Conowingo’s 401 Certification application and requesting that FERC decline to include the conditions required by MDE in April 2018.
On October 29, 2019, Generation and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. Pursuant to the Offer of Settlement, the parties submitted Proposed License Articles to FERC to be incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act. Among the Proposed License Articles are modifications to river flows to improve aquatic habitat, eel passage improvements, and initiatives to support rare, threatened and endangered wildlife. If FERC approves the Offer of Settlement and incorporates the Proposed License Articles into the new license without modification, then MDE would waive its rights to issue a 401 Certification and Generation would agree, pursuant to a separate agreement with MDE (MDE Settlement), to implement additional environmental protection, mitigation, and enhancement measures over the anticipated 50-year term of the new license. These measures address mussel restoration and other ecological and water quality matters, among other commitments. Exelon’s commitments under the various provisions of the Offer of Settlement and MDE Settlement are not effective unless and until FERC approves the Offer of Settlement, and issues the new license with the Proposed License Articles.
The financial impact of the DOI and MDE Settlements and other anticipated license commitments are estimated to be $11 million to $14 million per year, on average, recognized over the new license term, including capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new license. As of December 31, 2020, $45 million of direct costs associated with Conowingo licensing efforts have been capitalized. Generation's current depreciation provision for Conowingo assumes renewal of the FERC license.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Peach Bottom Units 2 and 3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3, which was approved on March 6, 2020. Peach Bottom Units 2 and 3 are now licensed to operate through 2053 and 2054, respectively. See Note 13 — Debt8 – Property, Plant, and Credit AgreementsEquipment for additional information.information regarding the estimated useful life and depreciation provisions for Peach Bottom.
3. 4. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue and no variable consideration for regulated electric and gas tariff sales and regulated transmission services unless noted below.
Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, the Registrant's have elected to use the right to invoice practical expedient for the contracts within these revenue categories andRegistrants generally
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
recognize revenue in the amount for which they have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.
Competitive Power Sales (Exelon and Generation)
Generation sells power and other energy-related commoditiesCombined Notes to both wholesale and retail customers across multiple geographic regions through its customer-facing business, Constellation. Power sale contracts generally contain various performance obligations including the delivery of power and other energy-related commodities such as capacity, ZECs, RECs or other ancillary services. Certain performance obligations such as power and capacity are generally delivered over time whereas other performance obligations such as RECs and ZECs are generally delivered at a pointConsolidated Financial Statements
(Dollars in time. In either case, revenues related to all of the performance obligations in such bundled power sale contracts are generally recognized concurrently as the power is generated. Except as noted in the paragraph below, there are no significant judgments in allocating the transaction price since all performance obligations are satisfied simultaneously upon the generation of power. Payment terms generally require that the customers pay for the power or the energy-related commodity within the month following delivery to the customer and there are generally no significant financing components.millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
| | | | | | | | | | | | | | |
| Revenue Source | Description | Performance Obligation | Timing of Revenue Recognition | Payment Terms |
| Competitive Power Sales (Exelon and Generation) | Sales of power and other energy-related commodities to wholesale and retail customers across multiple geographic regions through its customer-facing business, Constellation. | Various including the delivery of power (generally delivered over time) and other energy-related commodities such as capacity (generally delivered over time), ZECs, RECs or other ancillary services (generally delivered at a point in time). | Concurrently as power is generated for bundled power sale contracts. (a) | Within the month following delivery to the customer. |
| Competitive Natural Gas Sales (Exelon and Generation) | Sales of natural gas on a full requirement basis or for an agreed upon volume to commercial and residential customers. | Delivery of natural gas to the customer. | Over time as the natural gas is delivered and consumed by the customer. | Within the month following delivery to the customer. |
| Other Competitive Products and Services (Exelon and Generation) | Sales of other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers. | Construction and/or installation of the asset for the customer. | Revenues and associated costs are recognized throughout the contract term using an input method to measure progress towards completion.(b) | Within 30 or 45 days from the invoice date. |
| Regulated Electric and Gas Tariff Sales (Exelon and the Utility Registrants) | Sales of electricity and electricity distribution services (the Utility Registrants) and natural gas and gas distribution services (PECO, BGE, and DPL) to residential, commercial, industrial, and governmental customers through regulated tariff rates approved by state regulatory commissions. | Delivery of electricity and/or natural gas. | Over time (each day) as the electricity and/or natural gas is delivered to customers. Tariff sales are generally considered daily contracts as customers can discontinue service at any time. (c) | Within the month following delivery of the electricity or natural gas to the customer. |
| Regulated Transmission Services (Exelon and the Utility Registrants) | The Utility Registrants provide open access to their transmission facilities to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants pursuant to filed tariffs at cost-based rates approved by FERC. | Various including (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid. | Over time utilizing output methods to measure progress towards completion. (d) | Paid weekly by PJM. |
__________
(a)Certain contracts may contain limits on the total amount of revenue weExelon and Generation are able to collect over the entire term of the contract. In such cases, the RegistrantsExelon and Generation estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.
Competitive Natural Gas Sales (Exelon and Generation)
Generation sells natural gas on a full requirements basis or for an agreed upon volume to both commercial and residential customers. The primary performance obligation associated with natural gas sale contracts is the delivery of the natural gas to the customer. Revenues related to the sale of natural gas are recognized over time as the natural gas is delivered to and consumed by the customer. Payment from customers is typically due within the month following delivery of the natural gas to the customer and there are generally no significant financing components.
Other Competitive Products and Services (Exelon and Generation)
Generation also sells other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers. These contracts generally contain a single performance obligation, which is the construction and/or installation of the asset for the customer. The average contract term for these projects is approximately 18 months. Revenues, and associated costs, are recognized throughout the contract term using an input method to measure progress towards completion. (b)The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. Payments from customers are typically due within 30 or 45 days from the date the invoiceThe average contract term for these projects is generated and sent to the customer.approximately 18 months.
Regulated Electric and Gas Tariff Sales (Exelon and the Utility Registrants)
The Utility Registrants sell electricity and electricity distribution services to residential, commercial, industrial and governmental customers through regulated tariff rates approved by their state regulatory commissions. PECO, BGE and DPL also sell natural gas and gas distribution services to residential, commercial, and industrial customers through regulated tariff rates approved by their state regulatory commissions. The performance obligation associated with these tariff sale contracts is the delivery of electricity and/or natural gas. Tariff sales are generally considered daily contracts given that customers can discontinue service at any time. Revenues are generally recognized over time (each day) as the electricity and/or natural gas is delivered to customers. Payment terms generally require that customers pay for the services within the month following delivery of the electricity or natural gas to the customer and there are generally no significant financing components or variable consideration.
(c)Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Regulated Transmission Services (Exelon and the Utility Registrants)
Under FERC’s open access transmission policy, the Utility Registrants, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants are members of PJM, the regional transmission organization designated by FERC to coordinate the movement of wholesale electricity in PJM’s region, which includes portions of the mid-Atlantic and Midwest. In accordance with FERC-approved rules, the Utility Registrants and other transmission owners in the PJM region make their transmission facilities available to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants and other transmission owners. The performance obligations associated with the Utility Registrants’ contract with PJM include (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid. These performance obligations are satisfied over time, and Utility Registrants utilize output methods to measure the progress towards their completion. (d)Passage of time is used for NITS and access to the wholesale grid and MWhsMWHs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services. PJM pays the Utility Registrants for these services on a weekly basis and there are no financing components or variable consideration.
Costs to Obtain or Fulfill a Contract with a Customer (Exelon and Generation)
Generation incurs incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions. Generation hascommissions, are capitalized suchwhen incurred as contract acquisition costs in the amount of $32 million and $26 millionwere immaterial as of December 31, 20182020 and December 31, 2017, respectively, within Other current assets and Other deferred debits in Exelon’s and Generation’s Consolidated Balance Sheets. These costs are capitalized when incurred and amortized using the straight-line method over the average length of such retail contracts, which is approximately 2 years. Exelon and Generation recognized amortization expense associated with these costs in the amount of $22 million and $30 million for the twelve months endedDecember 31, 2018, and December 31, 2017, respectively, within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Generation does not incur material costs to fulfill contracts with customers that are not already capitalized under existing guidance. In addition, the2019. The Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.
Contract Balances (All Registrants)
Contract AssetsOther State Regulatory Matters
Generation records contract assets for the revenue recognized on the constructionIllinois Regulatory Matters
Energy Efficiency Formula Rate (Exelon and installation ofComEd). FEJA allows ComEd to defer energy efficiency assets and new power generating facilities before Generation has an unconditional right to billcosts (except for and receiveany voltage optimization costs which are recovered through the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current assets and Accounts receivable, net - Customer, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets. The following table provides a rollforward of the contract assets reflected in Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to December 31, 2018:
|
| | | | |
| Contract Assets | | Exelon and Generation |
| Balance as of January 1, 2018 | | $ | 283 |
|
| Increases as a result of changes in the estimate of the stage of completion | | 50 |
|
| Amounts reclassified to receivables | | (146 | ) |
| Balance at December 31, 2018 | | $ | 187 |
|
The Utility Registrants do not have any contract assets.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Contract Liabilities
Generation records contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. The Generation contract liability related to the Illinois ZEC program includes certain amounts with ComEd that are eliminated in consolidation in Exelon’s Consolidated Statements of Operations and Consolidated Balance Sheets. Generation records contract liabilities within Other current liabilities and Other noncurrent liabilities within Exelon’s and Generation’s Consolidated Balance Sheets. The following table provides a rollforward of the contract liabilities reflected in Exelon's and Generation's Consolidated Balance Sheet from January 1, 2018 to December 31, 2018:
|
| | | | | | | |
| Contract Liabilities | Exelon | | Generation |
| Balance as of January 1, 2018 | $ | 35 |
| | $ | 35 |
|
| Increases as a result of additional cash received or due | 179 |
| | 465 |
|
| Amounts recognized into revenues | (187 | ) | | (458 | ) |
| Balance at December 31, 2018 | $ | 27 |
| | $ | 42 |
|
The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of December 31, 2018 and December 31, 2017, the Utility Registrants' contract liabilities were immaterial.
Transaction Price Allocated to Remaining Performance Obligations (All Registrants)
The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2018. Generation has elected the exemption which permits the exclusion from this disclosure of certain variable contract consideration. As such, the majority of Generation’s power and gas sales contracts are excluded from this disclosure as they contain variable volumes and/or variable pricing. Thus, this disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
The majority of the Utility Registrants’ tariff sale contracts are generally day-to-day contracts and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure. Further, the Utility Registrants have elected the exemption to not disclose the transaction price allocation to remaining performance obligations for contracts with an original expected duration of one year or less. As such, gas and electric tariff sales contracts and transmission revenue contracts are excluded from this disclosure.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and thereafter | | Total |
| Exelon | $ | 631 |
| | $ | 329 |
| | $ | 119 |
| | $ | 47 |
| | $ | 138 |
| | $ | 1,264 |
|
| Generation | 631 |
| | 329 |
| | 119 |
| | 47 |
| | 138 |
| | 1,264 |
|
Revenue Disaggregation (All Registrants)
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 24 — Segment Information for the presentation of the Registrant's revenue disaggregation.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
4. Regulatory Matters (All Registrants)
The following matters below discuss the status of material regulatory and legislative proceedings of the Registrants.
Utility Regulatory Matters (Exelon and the Utility Registrants)
Distribution Base Rate Case Proceedings
The following tables show the completed and pending distribution base rate case proceedings in 2018.
Completed Distribution Base Rate Case Proceedings
|
| | | | | | | | | | | | | |
| Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase (Decrease) | | Approved Revenue Requirement Increase (Decrease) | | Approved ROE | Approval Date | Rate Effective Date |
ComEd - Illinois (Electric)(b) | April 16, 2018 | $ | (23 | ) | (a) | $ | (24 | ) | (a) | 8.69 | % | December 4, 2018 | January 1, 2019 |
PECO - Pennsylvania (Electric)(c) | March 29, 2018 | $ | 82 |
| (a) | $ | 25 |
| (a) | N/A | December 20, 2018 | January 1, 2019 |
| BGE - Maryland (Natural Gas) | June 8, 2018 (amended August 24, 2018 and October 12, 2018) | $ | 61 |
| | $ | 43 |
| | 9.8 | % | January 4, 2019 | January 4, 2019 |
| Pepco - Maryland (Electric) | January 2, 2018 (amended February 5, 2018) | $ | 3 |
| (a) | $ | (15 | ) | (a) | 9.5 | % | May 31, 2018 | June 1, 2018 |
Pepco - District of Columbia (Electric)(d) | December 19, 2017 (amended February 9, 2018) | $ | 66 |
| | $ | (24 | ) | (a) | 9.525 | % | August 9, 2018 | August 13, 2018 |
DPL - Maryland (Electric)(e) | July 14, 2017 (amended November 16, 2017) | $ | 19 |
| | $ | 13 |
| | 9.5 | % | February 9, 2018 | February 9, 2018 |
| DPL - Delaware (Electric) | August 17, 2017 (amended February 9, 2018) | $ | 12 |
| (a) | $ | (7 | ) | (a) | 9.7 | % | August 21, 2018 | March 17, 2018 |
| DPL - Delaware (Natural Gas) | August 17, 2017 (amended February 9, 2018) | $ | 4 |
| (a) | $ | (4 | ) | (a) | 9.7 | % | November 8, 2018 | March 17, 2018 |
__________
| |
(a) | Includes the annual ongoing TCJA tax savings further discussed below. |
| |
(b) | Pursuant to EIMA and FEJA, ComEd’s electric distribution rates are established through a performance-based formula, which sunsets at the end of 2022. ComEd is required to file an annual update to its electric distribution formula rate on or before May 1st, with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation).
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd’s 2018 approved revenue requirement above reflects a decrease of $58 million for the initial year revenue requirement for 2018 and an increase of $34 million related to the annual reconciliation for 2017. The revenue requirement for 2018 and the annual reconciliation for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.52% inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory assets associated with its electric distribution formula rate.
Duringrate) as a separate regulatory asset that is recovered through the first quarter of 2018, ComEd revised its electric distributionenergy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to implement revenue decoupling provisions provided for under FEJA. Asits weighted average cost of capital, which is based on a result of this revision,year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer or numbers of customers.rate. Beginning January 1, 2018 through December 31, 2030, the ROE that ComEd began reflecting the impacts of this change inearns on its Operating revenues and electric distribution formula rateenergy efficiency regulatory asset in the first quarteris subject to a maximum downward or upward adjustment of 2017.
| |
(c) | The PECO base rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE. |
| |
(d) | On September 7, 2018, Pepco submitted an updated filing for an increase of $4 million to the customer base rate credit established in connection with the merger between Exelon and PHI for residential customers, representing the TCJA benefits for the period January 1, 2018 through August 12, 2018. |
| |
(e) | The DPL Maryland base rate case proceeding was resolved through a settlement agreement, which did not specify an overall ROE. The settlement agreement included an ROE of 9.5% solely for purposes of calculating AFUDC and regulatory asset carrying costs. |
In the second quarter200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of 2018, DPL discovered a rate design issue in Maryland such that the current rates were not sufficient to collect the full amountor exceeds specified percentage benchmarks of the $13 million revenue increase agreed to by the parties in the recent settlement. On September 5, 2018, the MDPSC approved DPL’s proposed revisions to resolve the rate design issue on a prospective basis, effective September 5, 2018.
Pending Distribution Base Rate Case Proceedings
|
| | | | | | | | |
| Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase |
| Requested ROE | Expected Approval Timing |
| ACE - New Jersey (Electric) | August 21, 2018 (amended November 19, 2018) | $ | 122 |
| (a) | 10.1 | % | Third quarter of 2019(b) |
| Pepco - Maryland (Electric) | January 15, 2019 | $ | 30 |
| | 10.3 | % | Third quarter of 2019 |
__________
| |
(a) | Requested increaseits annual incremental savings goal. ComEd is before New Jersey sales and use tax and includes $40 million of higher depreciation expense related to its updated depreciation study and the annual ongoing TCJA tax savings further discussed below. |
| |
(b) | ACE plans to put interim rates in effect on or around May 21, 2019, subject to refund, as allowed by the regulation. |
Transmission Formula Rates
Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’s, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approvedits energy efficiency formula rate on or before May 15,June 1st each year, with the resulting rates effective on June 1in January of the samefollowing year. The annual formula rate update is based on prior year actual costs andprojected current year energy efficiency costs, PJM capacity revenues, and the projected capital additionsyear-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect beginning June 1 offor the prior year and actual costs incurred for thatfrom the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions similar to those in ComEd’s electric distribution formula rate.
During 2020, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For 2018, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:
Note 3 — Regulatory Matters
|
| | | | | | | | | | | | | | |
| Registrant | Initial Revenue Requirement (Decrease) Increase(b) | Annual Reconciliation Increase/(Decrease) | Total Revenue Requirement (Decrease) Increase |
| Allowed Return on Rate Base(d) | Allowed ROE(e) |
ComEd(a) | $ | (44 | ) | $ | 18 |
| $ | (26 | ) |
| 8.32 | % | 11.50 | % |
BGE(a) | 10 |
| 4 |
| 26 |
| (c) | 7.61 | % | 10.50 | % |
| Pepco | 6 |
| 2 |
| 8 |
|
| 7.82 | % | 10.50 | % |
| DPL | 14 |
| 13 |
| 27 |
|
| 7.29 | % | 10.50 | % |
ACE(a) | 4 |
| (4 | ) | — |
|
| 8.02 | % | 10.50 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Filing Date | | Requested Revenue Requirement Increase | | Approved Revenue Requirement Increase | | Approved ROE | | Approval Date | | Rate Effective Date |
| May 21, 2020 | | $ | 48 | | | $ | 48 | | (a) | 8.38 | % | | December 2, 2020 | | January 1, 2021 |
___________________
| |
(a) | The time period for any formal challenges to the annual transmission formula rate update filings expired with no formal challenges submitted. |
| |
(b) | The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. See further discussion below. |
| |
(c) | The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission service to specifically designated load by BGE. |
| |
(d) | Represents the weighted average debt and equity return on transmission rate bases. |
| |
(e) | As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO. |
Pending Transmission Formula Rate(a)ComEd’s 2021 approved revenue requirement above reflects an increase of $45 million for the initial year revenue requirement for 2021 and an increase of $3 million related to the annual reconciliation for 2019. The revenue requirement for 2021 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.28% inclusive of an allowed ROE of 8.38%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for 2019 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.56% inclusive of an allowed ROE of 8.96%, which includes an upward performance adjustment that can either increase or decrease the ROE. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate.
Maryland Regulatory Matters
The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and PECO)BGE).On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017 (as amended on January 22, 2018), BGE filed an application with the MDPSC seeking approval for a new gas infrastructure replacement plan and associated surcharge, effective for the five-year period from 2019 through 2023. On May 30, 2018, the MDPSC approved with modifications a new infrastructure plan and associated surcharge, subject to refund,BGE's acceptance of the Order. On June 1, 2018, BGE accepted the MDPSC Order and set the matterassociated surcharge became effective January 2019. The five-year plan calls for hearingcapital expenditures over the 2019-2023 timeframe of $732 million with an associated revenue requirement of $200 million.
Cash Working Capital Order (Exelon and settlement judge procedures.BGE). On May 4, 2018,November 17, 2016, the ChiefMDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its POLR service, also known as SOS, as well as other components that make up the Administrative Law Judge terminated settlement judge proceduresCharge, the mechanism that enables BGE to recover its SOS-related costs. The Administrative Charge is comprised of five components: CWC, uncollectibles, incremental costs, return, and designatedan administrative adjustment, which acts as a new presiding judge. PECOproxy for retail suppliers’ costs. The MDPSC accepted BGE's positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a return on the SOS. Subsequently, the MDPSC Staff and residential consumer advocate sought clarification and appealed the amount of return awarded to BGE on the SOS. On July 27, 2020, the Maryland Court of Special Appeals affirmed the circuit court’s judgment affirming the MDPSC’s decision. No party appealed the decision to the Maryland Court of Appeals. Also, in BGE’s 2019 electric and gas distribution base rate proceeding, the MDPSC established a normalized administrative adjustment. However, a group of electric suppliers appealed the MDPSC’s decision to the Circuit Court for Baltimore City. BGE cannot predict the outcome of this proceeding, orappeal.
New Jersey Regulatory Matters
ACE Infrastructure Investment Program Filing (Exelon, PHI, and ACE). On February 28, 2018, ACE filed with the transmission formula FERC may approve.NJBPU the company’s IIP proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement.
Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE).On May 11, 2018, pursuantAugust 26, 2020, ACE filed an application with the NJBPU as was required seeking approval to deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consists of estimated costs totaling $220 million, with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that involves the transmission formula rate request discussed above, PECO made its first annual formula rate update, which includedinstallation of an integrated system of smart meters for all customers accompanied by the requisite communications facilities and data management systems. ACE is seeking authority to recover these estimated investments through a revenue decrease of $6 million. The revenue decrease of $6 million included an approximately $20 million reduction as a resultcombination of the tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.
Tax CutsACE IIP rider mechanism and Jobs Act
The Utility Registrants have made filings with their state regulatory commissions to pass back tax savings related to TCJA to theirfuture distribution customers, which are detailed below. The tax savings include the benefit of lower federal income tax rates and the settlement ofbase rates. ACE currently expects a portion of the deferred income tax regulatory liabilities established upon the enactment of the TCJA. The ongoing annual TCJA tax savingsdecision in this matter in the table below representthird quarter of 2021 but cannot predict if the annual savings for distribution customers reflected inNJBPU will approve the initial customers rates approved after the TCJA. Subsequent annual TCJA tax savings will be approvedapplication as partfiled.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
|
| | | | | | | | |
| | Ongoing TCJA Tax Savings | Stub Period Bill Credit from TCJA Tax Savings |
| Registrant/Jurisdiction | Amount | Approval Date | Rate Effective Date | Stub Period | Approval Date | Refund Amount/Period |
| ComEd - Illinois (Electric) | $ | 201 |
| January 18, 2018 | February 1, 2018 | Not applicable |
| PECO - Pennsylvania (Electric) | $ | 71 |
| December 20, 2018 | January 1, 2019 | January 1, 2018 - December 31, 2018 | December 20, 2018 | $67 / 2019 (majority in January) |
| PECO - Pennsylvania (Natural Gas) | $ | 4 |
| (a) | July 1, 2018 | Not applicable |
| BGE - Maryland (Electric) | $ | 72 |
| January 31, 2018 | February 1, 2018 | January 1, 2018 - January 31, 2018
| To be addressed in next electric distribution base rate case |
| BGE - Maryland (Natural Gas) | $ | 31 |
| January 31, 2018 | February 1, 2018 | January 1, 2018 - January 31, 2018
| January 4, 2019 | $2 / Q1 2019 |
| Pepco - Maryland (Electric) | $ | 31 |
| May 31, 2018 | June 1, 2018 | January 1, 2018 - June 1, 2018 | May 31, 2018 |
$10 / July 2018 |
| Pepco - District of Columbia (Electric) | $ | 39 |
| August 9, 2018 | August 13, 2018 | January 1, 2018 - August 12, 2018
| September 7, 2018 | $20 / September 2018 |
| DPL - Maryland (Electric) | $ | 14 |
| April 18, 2018 | April 20, 2018 | January 1, 2018 - March 31, 2018
| April 18, 2018 | $2 / June 2018 |
| DPL - Delaware (Electric) | $ | 19 |
| August 21, 2018 | March 17, 2018 | February 1, 2018 - March 17, 2018
| August 21, 2018 | $3 / Q4 2018 |
| DPL - Delaware (Natural Gas) | $ | 7 |
| November 8, 2018 | March 17, 2018 | February 1, 2018 - March 17, 2018
| November 8, 2018 | $1 / Q4 2018 |
| ACE - New Jersey (Electric) | $ | 23 |
| August 29, 2018 | September 8, 2018 | January 1, 2018 - June 30, 2018
| August 29, 2018 | $6 / Q4 2018
|
__________
| |
(a) | On May 17, 2018, the PAPUC issued an order directing Pennsylvania utility companies without an existing base rate case, including PECO’s gas distribution business, to start passing back the savings from January 1, 2018 onward through a negative surcharge mechanism to be effective on July 1, 2018. Pursuant to that order, PECO filed a negative surcharge mechanism and began on July 1, 2018, to return the estimated annual 2018 tax savings above to its natural gas distribution customers. |
As discussed above, ComEd’s, BGE’s, Pepco’s, DPL’sNew Jersey Clean Energy Legislation (Exelon, PHI, and ACE’s transmission formula rates currently do not provideACE).On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey’s clean energy and energy efficiency programs and solar and RPS. On the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the pass back or recovery of income tax-related regulatory liabilities or assets,NJBPU that they meet certain requirements, including those established upon enactmentthat they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Electric distribution utilities in New Jersey, including ACE, began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the utility’s procurement of the TCJA. ZECs effective April 18, 2019. See Generation Regulatory Matters below for additional information.
Other Federal Regulatory Matters
Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE). On December 13, 2016 (as(and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and onfuture transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. In the fourth quarter of 2017, ComEd, BGE, Pepco, DPL, and ACE fully impaired their associated transmission-related income tax regulatory assets for the portion of the income tax regulatory assets that would have been previously amortized.
On February 23, 2018 (as amended on July 9, 2018), BGE and ComEd, Pepco, DPL, and ACE respectively, each filed with FERC to revise their transmission formula rate mechanisms to provide for pass back andpermit recovery of transmission-related income tax-relatedtax regulatory liabilities and assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.
On September 7, 2018, FERC issued orders rejecting 1) BGE’s rehearing request of FERC's November 16, 2017 order and 2) the February 23, 2018 (as amended on July 9, 2018) filing by ComEd, Pepco, DPL, and ACE for similar recovery.
On November 2, 2018, BGE filed an appeal of FERC's September 7, 2018 order to the U.S. Court of Appeals for the D.C. Circuit. On March 27, 2020, the U.S. Court of Appeals for the D.C. Circuit Court denied BGE’s November 2, 2018 appeal.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and credit TCJA transmission-related income tax regulatory liabilities to customers for the prospective period starting on October 1, 2018. On April 26, 2019, FERC issued an order accepting ComEd's, BGE's, Pepco's, DPL's, and ACE's October 1, 2018 filings, effective October 1, 2018, subject to refund and established upon enactmenthearing and settlement judge procedures. On April 24, 2020, ComEd, BGE, Pepco, DPL, ACE, and other parties filed a settlement agreement with FERC, which FERC approved on September 24, 2020. The settlement agreement provides for the recovery of ongoing transmission-related income tax regulatory assets and establishes the amount and amortization period for excess deferred income taxes resulting from TCJA. See discussion belowThe settlement resulted in a reduction to Operating revenues and an offsetting reduction to Income tax expense in the second quarter of 2020.
Regulatory Assets and Liabilities
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for additional information regarding these filings.approved regulatory programs.
See Note 14 - Income Taxes for additional information on Corporate Tax Reform.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE as of December 31, 2020 and December 31, 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory assets | | | | | | | | | | | | | | | |
| Pension and OPEB | $ | 3,010 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Pension and OPEB - merger related | 1,014 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred income taxes | 715 | | | 0 | | | 705 | | | 0 | | | 10 | | | 10 | | | 0 | | | 0 | |
| AMI programs - deployment costs | 174 | | | 0 | | | 0 | | | 109 | | | 65 | | | 35 | | | 30 | | | 0 | |
| AMI programs - legacy meters | 219 | | | 90 | | | 0 | | | 37 | | | 92 | | | 68 | | | 24 | | | 0 | |
| | | | | | | | | | | | | | | |
| Electric distribution formula rate annual reconciliations | (14) | | | (14) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Electric distribution formula rate significant one-time events | 117 | | | 117 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Energy efficiency costs | 982 | | | 982 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Fair value of long-term debt | 598 | | | 0 | | | 0 | | | 0 | | | 478 | | | 0 | | | 0 | | | 0 | |
| Fair value of PHI's unamortized energy contracts | 328 | | | 0 | | | 0 | | | 0 | | | 328 | | | 0 | | | 0 | | | 0 | |
| Asset retirement obligations | 135 | | | 92 | | | 21 | | | 18 | | | 4 | | | 3 | | | 0 | | | 1 | |
| MGP remediation costs | 285 | | | 271 | | | 10 | | | 4 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Renewable energy | 301 | | | 301 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Electric energy and natural gas costs | 95 | | | 0 | | | 0 | | | 23 | | | 72 | | | 37 | | | 5 | | | 30 | |
| Transmission formula rate annual reconciliations | 5 | | | 0 | | | 0 | | | 2 | | | 3 | | | 0 | | | 2 | | | 1 | |
| Energy efficiency and demand response programs | 572 | | | 0 | | | 0 | | | 289 | | | 283 | | | 203 | | | 80 | | | 0 | |
| | | | | | | | | | | | | | | |
| Under-recovered revenue decoupling | 113 | | | 0 | | | 0 | | | 20 | | | 93 | | | 93 | | | 0 | | | 0 | |
| Stranded costs | 25 | | | 0 | | | 0 | | | 0 | | | 25 | | | 0 | | | 0 | | | 25 | |
| Removal costs | 701 | | | 0 | | | 0 | | | 107 | | | 594 | | | 151 | | | 105 | | | 339 | |
| DC PLUG charge | 100 | | | 0 | | | 0 | | | 0 | | | 100 | | | 100 | | | 0 | | | 0 | |
| Deferred storm costs | 50 | | | 0 | | | 0 | | | 0 | | | 50 | | | 5 | | | 4 | | | 41 | |
| COVID-19 | 81 | | | 22 | | | 38 | | | 10 | | | 11 | | | 7 | | | 4 | | | 0 | |
| Under-recovered credit loss expense | 107 | | | 89 | | | 0 | | | 0 | | | 18 | | | 0 | | | 0 | | | 18 | |
| Other | 274 | | | 78 | | | 27 | | | 30 | | | 147 | | | 72 | | | 26 | | | 15 | |
| Total regulatory assets | 9,987 | | | 2,028 | | | 801 | | | 649 | | | 2,373 | | | 784 | | | 280 | | | 470 | |
| Less: current portion | 1,228 | | | 279 | | | 25 | | | 168 | | | 440 | | | 214 | | | 58 | | | 75 | |
| Total noncurrent regulatory assets | $ | 8,759 | | | $ | 1,749 | | | $ | 776 | | | $ | 481 | | | $ | 1,933 | | | $ | 570 | | | $ | 222 | | | $ | 395 | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory liabilities | | | | | | | | | | | | | | | |
| Deferred income taxes | $ | 4,502 | | | $ | 2,205 | | | $ | 0 | | | $ | 1,001 | | | $ | 1,296 | | | $ | 621 | | | $ | 404 | | | $ | 271 | |
| Nuclear decommissioning | 3,016 | | | 2,541 | | | 475 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Removal costs | 1,649 | | | 1,482 | | | 0 | | | 47 | | | 120 | | | 20 | | | 100 | | | 0 | |
| Electric energy and natural gas costs | 175 | | | 34 | | | 97 | | | 6 | | | 38 | | | 24 | | | 10 | | | 4 | |
| Transmission formula rate annual reconciliations | 52 | | | 2 | | | 12 | | | 0 | | | 38 | | | 23 | | | 9 | | | 6 | |
| Renewable portfolio standards costs | 427 | | | 427 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Stranded costs | 24 | | | 0 | | | 0 | | | 0 | | | 24 | | | 0 | | | 0 | | | 24 | |
| Other | 221 | | | 1 | | | 40 | | | 85 | | | 59 | | | 2 | | | 17 | | | 13 | |
| Total regulatory liabilities | 10,066 | | | 6,692 | | | 624 | | | 1,139 | | | 1,575 | | | 690 | | | 540 | | | 318 | |
| Less: current portion | 581 | | | 289 | | | 121 | | | 30 | | | 137 | | | 46 | | | 47 | | | 44 | |
| Total noncurrent regulatory liabilities | $ | 9,485 | | | $ | 6,403 | | | $ | 503 | | | $ | 1,109 | | | $ | 1,438 | | | $ | 644 | | | $ | 493 | | | $ | 274 | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2019 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory assets | | | | | | | | | | | | | | | |
| Pension and OPEB | $ | 2,784 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | — | | | $ | 0 | | | $ | 0 | |
| Pension and OPEB - merger related | 1,138 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred income taxes | 528 | | | 0 | | | 518 | | | 0 | | | 10 | | | 10 | | | 0 | | | 0 | |
| AMI programs - deployment costs | 207 | | | 0 | | | 0 | | | 129 | | | 78 | | | 43 | | | 35 | | | 0 | |
| AMI programs - legacy meters | 276 | | | 113 | | | 12 | | | 45 | | | 106 | | | 79 | | | 27 | | | 0 | |
| Electric distribution formula rate annual reconciliations | 34 | | | 34 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Electric distribution formula rate significant one-time events | 66 | | | 66 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Energy efficiency costs | 746 | | | 746 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Fair value of long-term debt | 650 | | | 0 | | | 0 | | | 0 | | | 523 | | | 0 | | | 0 | | | 0 | |
| Fair value of PHI's unamortized energy contracts | 443 | | | 0 | | | 0 | | | 0 | | | 443 | | | 0 | | | 0 | | | 0 | |
| Asset retirement obligations | 127 | | | 85 | | | 23 | | | 16 | | | 3 | | | 2 | | | 0 | | | 1 | |
| MGP remediation costs | 302 | | | 287 | | | 11 | | | 4 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Renewable energy | 301 | | | 301 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Electric energy and natural gas costs | 110 | | | 0 | | | 6 | | | 36 | | | 68 | | | 43 | | | 5 | | | 20 | |
| Transmission formula rate annual reconciliations | 11 | | | 0 | | | 0 | | | 1 | | | 10 | | | 1 | | | 2 | | | 7 | |
| Energy efficiency and demand response programs | 572 | | | 0 | | | 0 | | | 303 | | | 269 | | | 196 | | | 73 | | | 0 | |
| Merger integration costs | 32 | | | 0 | | | 0 | | | 2 | | | 30 | | | 15 | | | 8 | | | 7 | |
| Under-recovered revenue decoupling | 37 | | | 0 | | | 0 | | | 8 | | | 29 | | | 29 | | | 0 | | | 0 | |
| Stranded costs | 37 | | | 0 | | | 0 | | | 0 | | | 37 | | | 0 | | | 0 | | | 37 | |
| Removal costs | 641 | | | 0 | | | 0 | | | 67 | | | 574 | | | 152 | | | 100 | | | 324 | |
| DC PLUG charge | 126 | | | 0 | | | 0 | | | 0 | | | 126 | | | 126 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | |
| Other | 337 | | | 129 | | | 25 | | | 26 | | | 167 | | | 76 | | | 24 | | | 29 | |
| Total regulatory assets | 9,505 | | | 1,761 | | | 595 | | | 637 | | | 2,473 | | | 772 | | | 274 | | | 425 | |
| Less: current portion | 1,170 | | | 281 | | | 41 | | | 183 | | | 412 | | | 188 | | | 52 | | | 57 | |
| Total noncurrent regulatory assets | $ | 8,335 | | | $ | 1,480 | | | $ | 554 | | | $ | 454 | | | $ | 2,061 | | | $ | 584 | | | $ | 222 | | | $ | 368 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2019 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory liabilities | | | | | | | | | | | | | | | |
| Deferred income taxes | $ | 4,944 | | | $ | 2,297 | | | $ | 0 | | | $ | 1,089 | | | $ | 1,558 | | | $ | 725 | | | $ | 477 | | | $ | 356 | |
| Nuclear decommissioning | 3,102 | | | 2,622 | | | 480 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Removal costs | 1,621 | | | 1,435 | | | 0 | | | 58 | | | 128 | | | 20 | | | 108 | | | 0 | |
| | | | | | | | | | | | | | | |
| Electric energy and natural gas costs | 109 | | | 45 | | | 56 | | | 0 | | | 8 | | | 0 | | | 8 | | | 0 | |
| Transmission formula rate annual reconciliations | 34 | | | 6 | | | 28 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | |
| Other | 582 | | | 337 | | | 37 | | | 81 | | | 83 | | | 9 | | | 18 | | | 26 | |
| Total regulatory liabilities | 10,392 | | | 6,742 | | | 601 | | | 1,228 | | | 1,777 | | | 754 | | | 611 | | | 382 | |
| Less: current portion | 406 | | | 200 | | | 91 | | | 33 | | | 70 | | | 8 | | | 37 | | | 25 | |
| Total noncurrent regulatory liabilities | $ | 9,986 | | | $ | 6,542 | | | $ | 510 | | | $ | 1,195 | | | $ | 1,707 | | | $ | 746 | | | $ | 574 | | | $ | 357 | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
| Pension and OPEB | Primarily reflects the Utility Registrants' portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and OPEB plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets. | The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. See Note 15 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. | No |
| Pension and OPEB - merger related | The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. See Note 15 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. | Legacy Constellation - 2038 Legacy PHI - 2032 | No |
| Deferred income taxes | Deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA. These amounts include transmission-related regulatory liabilities that require FERC approval separate from the transmission formula rate. See Transmission-Related Income Tax Regulatory Assets section above for additional information. | Over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules. | No |
| | | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
AMI programs - deployment costs
| Installation costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters. | BGE - 2026 Pepco - 2027 DPL - 2030 | Yes |
| AMI programs - legacy meters | Early retirement costs of legacy meters. | ComEd - 2028 BGE - 2026 Pepco - 2027 DPL - 2030 | ComEd, Pepco (District of Columbia), DPL (Delaware) - Yes BGE, Pepco (Maryland), DPL (Maryland) - No |
Electric distribution formula rate annual reconciliations
| Under/(Over)-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which is updated annually with rates effective on January 1st. | 2022
| Yes |
| Electric distribution formula rate significant one-time events | Deferred distribution service costs related to ComEd's significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event. | 2024 | Yes |
Energy efficiency costs
| ComEd's costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure. | 2031 | Yes
|
Fair value of long-term debt
| Represents the difference between the carrying value and fair value of long-term debt of PHI and BGE of $478 million and $120 million, respectively, as of December 31, 2020 and $523 million and $127 million, respectively, as of December 31, 2019, as of the PHI and Constellation merger dates. | BGE - 2036
PHI - 2045 | No |
Fair value of PHI’s unamortized energy contracts
| Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's, and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date. | 2036 | No |
| Asset retirement obligations | Future legally required removal costs associated with existing AROs. | Over the life of the related assets. | Yes, once the removal activities have been performed. |
MGP remediation costs
| Environmental remediation costs for MGP sites recorded at ComEd, PECO, and BGE.
| Over the expected remediation period. See Note 19 — Commitments and Contingencies for additional information. | No |
| | | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
| Renewable energy | Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts. | 2032 | No |
| Electric energy and natural gas costs | Under (over)-recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders. | 2025 | DPL (Delaware), ACE - Yes ComEd, PECO, BGE, Pepco, DPL (Maryland) - No |
| Transmission formula rate annual reconciliations | Under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants’ FERC formula rates, which are updated annually with rates effective each June 1st. | 2022 | Yes |
| Energy efficiency and demand response programs | Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers. | PECO - 2021 BGE - 2025 Pepco, DPL - 2035 | BGE, Pepco, DPL - Yes PECO - Yes on capital investment recovered through this mechanism |
| Merger integration costs | Integration costs to achieve distribution synergies related to the Constellation merger and PHI acquisition. Costs for Pepco (Maryland) and Pepco (District of Columbia) were $3 million and $9 million, respectively as of December 31, 2020, which are included in Other in the table above, and $6 million and $9 million, respectively as of December 31, 2019. | BGE - 2021 Pepco - 2021 DPL- 2026 ACE - 2022 | BGE, Pepco (Maryland), DPL - Yes
Pepco (District of Columbia), ACE - No |
Under (over)-recovered revenue decoupling
| Electric and / or gas distribution costs recoverable from or (refundable) to customers under decoupling mechanisms. | BGE and DPL - 2021 Pepco (Maryland) - $16 million - 2021 Pepco (District of Columbia) - $31 million - 2021; $46 million to be determined by the DCPSC | BGE, Pepco, DPL - No |
Stranded costs
| The regulatory asset represents certain stranded costs associated with ACE's former electricity generation business. The regulatory liability represents overcollection of a customer surcharge collected by ACE to fund principal and interest payments on Transition Bonds of ACE Transition Funding that securitized such costs. | Stranded costs - 2022
Overcollection - To be determined by NJBPU | Stranded costs - Yes
Overcollection - No |
| | | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
Removal costs
| For BGE, Pepco, DPL, and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, Pepco, and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes. | BGE, Pepco, DPL, and ACE - Asset is generally recovered over the life of the underlying assets.
ComEd, BGE, Pepco, and DPL - Liability is reduced as costs are incurred. | Yes |
DC PLUG charge
| Costs associated with DC PLUG, which is a projected six year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia. Rates for the DC PLUG initiative went into effect on February 7, 2018. | 2021 - $30 million $70 million to be determined based on future biennial plans filed with the DCPSC. | Portion of asset funded by Pepco-Yes
|
| Deferred storm costs | For Pepco, DPL, and ACE amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland and New Jersey jurisdictions. | Pepco - 2024
DPL - $2 million - 2025; $2 million not currently being recovered
ACE - $5 million - 2021; $36 million not currently being recovered | Pepco, DPL - Yes
ACE - No |
Nuclear decommissioning
| Estimated future decommissioning costs for the Regulatory Agreement Units that are less than the associated NDT fund assets. See Note 10 — Asset Retirement Obligations for additional information. | Not currently being refunded.
| No |
| COVID-19 | See COVID-19 section below for detail on the COVID-19 regulatory asset. | ComEd - 2024
BGE - 2025
PECO, Pepco, DPL, and ACE - Not currently being recovered. | ComEd and BGE - Yes
PECO, Pepco, DPL, and ACE - No |
| | | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
| Under (over) -recovered credit loss expense | For ComEd and ACE, amounts represent the difference between annual credit loss expense and revenues collected in rates through ICC and NJBPU-approved riders. The difference between net credit loss expense and revenues collected through the rider each calendar year for ComEd is recovered or refunded over a twelve-month period beginning in June of the following calendar year. ACE intends to recover/refund from June through May of each respective year, subject to approval of the NJBPU. | ComEd - 2023
ACE - To be determined by NJBPU. | No |
| Renewable portfolio standards costs | Represents an overcollection of funds from both ComEd customers and alternative retail electricity suppliers to be spent on future renewable energy procurements. Costs were $320 million as of December 31, 2019, which are included in Other in the 2019 table above. | To be determined by the IPA and ICC. | No |
COVID-19 (Exelon and the Utility Registrants). Starting in March of 2020, the Utility Registrants temporarily suspended customer disconnections for non-payment and temporarily ceased new late payment fees for all customers and restored service to customers upon request who were disconnected in the last twelve months. The duration and extent of these measures varies by jurisdiction. While these measures are no longer in place for some jurisdictions as of December 31, 2020, they are expected to continue through the first quarter of 2021 in other jurisdictions. Typically, the Utility Registrants recover credit loss expense through regulatory required programs or distribution base rate cases. ComEd and ACE have existing mechanisms for recovery of credit loss expense. For those jurisdictions without an existing regulatory required program to recover credit loss expense, the Utility Registrants are pursuing strategies to recover incremental costs being incurred as a result of COVID-19:
•In the period of April to July of 2020, the MDPSC, the DCPSC, the DPSC, and the NJBPU issued orders authorizing the creation of regulatory assets to track incremental COVID-19 related costs.
•In May of 2020, the PAPUC issued a Secretarial Letter authorizing the creation of regulatory assets to track incremental credit loss expense related to COVID-19.
The Utility Registrants have also incurred direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of their employees.
The Utility Registrants have recorded regulatory assets for the impacts of COVID-19 reflecting primarily incremental credit losses and direct costs, partially offset by a decrease in travel costs at BGE and PHI. Refer to the Regulatory assets table above for amounts as of December 31, 2020. The Utility Registrants expect to seek recovery in upcoming distribution base rate cases.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Capitalized Ratemaking Amounts Not Recognized
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.
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| Exelon | | ComEd(a) | | PECO | | BGE(b) | | PHI | | Pepco(c) | | DPL(c) | | ACE |
| December 31, 2020 | $ | 51 | | | $ | (1) | | | $ | 0 | | | $ | 45 | | | $ | 7 | | | $ | 4 | | | $ | 3 | | | $ | 0 | |
| December 31, 2019 | $ | 63 | | | $ | 3 | | | $ | 0 | | | $ | 53 | | | $ | 7 | | | $ | 4 | | | $ | 3 | | | $ | 0 | |
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(a)Reflects ComEd's unrecognized equity returns/(losses) earned/(incurred) for ratemaking purposes on its electric distribution formula rate regulatory assets.
(b)BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.
(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.
Generation Regulatory Matters (Exelon and Generation)
Illinois Regulatory Matters
Zero Emission Standard.Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1, and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event.
Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. The ZEC price was initially established at $16.50 per MWh of production, subject to annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices. Illinois utilities are required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017 to May 31, 2018, and subsequent delivery year, June 1, 2018 to May 31, 2019, the ZEC annual cost cap was set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. During the first quarter of 2018, Generation recognized $150 million of revenue related to ZECs generated from June 1, 2017 through December 31, 2017.
New Jersey Regulatory Matters
New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $69 million and $53 million for the year ended December 31, 2020 and 2019, respectively. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU's decision to the New Jersey Superior Court. Briefing has been completed, and on December 9, 2020, oral argument took place. On October 1, 2020, PSEG and Generation filed applications seeking ZECs for the second eligibility period (June 2022 through May 2025). The NJBPU will act on the applications by the end of April 2021. Exelon and Generation cannot predict the outcome of the appeal. See Note 7 - Early Plant Retirements for additional information related to Salem.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
New York Regulatory Matters
New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which is a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC to be Generation's FitzPatrick, Ginna, and Nine Mile Point nuclear facilities.
On November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. On October 8, 2019, the court dismissed all remaining claims. The petitioners filed a notice of appeal on November 4, 2019 and originally had until May 4, 2020 to file their brief. Due to COVID-19 related restrictions, the court extended the deadline to July 29, 2020. Petitioners did not file a brief by the deadline, so the case is deemed dismissed. Petitioners are permitted up to one year from July 29, 2020 to file a motion to vacate the dismissal if they can show good cause for the delay.
See Note 7 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point.
New England Regulatory Matters
Mystic Units 8 & 9 and Everett Marine Terminal Cost of Service Agreement (Exelon and Generation). On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 & 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service compensation, reflecting a number of adjustments to the annual fixed revenue requirement, and allowing for recovery of a substantial portion of the costs associated with the adjacent Everett Marine Terminal acquired by Generation in October 2018. Those adjustments were reflected in a compliance filing made on March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. On January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings in the order.
On July 17, 2020, FERC issued three orders, which together affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of the Everett Marine Terminal. FERC directed a downward adjustment to the rate base for Mystic Units 8 and 9, the effect of which will be partially offset by elimination of a crediting mechanism for third party gas sales during the term of the cost of service agreement. A compliance filing was submitted on September 15, 2020 and is pending. Several parties filed protests to the compliance filing on the issue of how gross plant in-service was calculated and Generation filed an answer to the protests on October 21, 2020. On July 28, 2020, FERC ordered additional briefings in the ROE proceeding. On December 21, 2020, FERC issued an order on rehearing of the three July 17, 2020 orders, clarifying several cost of service provisions.
On August 25, 2020, a group of New England generators filed a complaint against Generation seeking to extend the scope of the claw back provision in the cost-of-service agreement, whereby Generation would refund certain amounts recovered during the term of the cost of service if it returns to market afterwards. On September 14, 2020, Generation filed an answer to the complaint arguing that the complaint is procedurally improper and a collateral attack on existing FERC orders, and pointing out that the ISO-NE tariff contains protections against the New England generators' concerns that they failed to mention. On September 28, 2020, New England generators filed an answer to Generation’s answer. Generation cannot predict the outcome of this proceeding.
On June 10, 2020, Generation filed a complaint with FERC against ISO-NE on the grounds that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic for transmission security for the 2024 to 2025 Capacity Commitment Period (FCA 15) and that the modifications that ISO-NE made to its unfiled planning procedures to avoid retaining Mystic should have been filed with FERC for approval. On July 27, 2020, ISO-NE issued a memo to NEPOOL announcing its determination pursuant to its unfiled planning procedures that Mystic Units 8 and 9 are not needed for FCA 15 for transmission security. It had previously determined Mystic Units 8 and 9 are not needed for fuel security. On August 17, 2020, FERC issued an order denying the complaint. On September 16,
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
2020, Generation filed a request for rehearing with FERC. On October 19, 2020, FERC denied rehearing by operation of law and on December 18, 2020, Generation appealed to the U.S. Court of Appeals for the D.C. Circuit. The timing and the outcome of this proceeding is uncertain.
See Note 7 — Early Plant Retirements and Note 12 — Asset Impairments for additional information on the impacts of Generation’s August 2020 decision to retire Mystic Units 8 & 9 upon expiration of the cost of service agreement.
Federal Regulatory Matters
PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a MOPR. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a state government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the MOPR in NYISO applies only to certain resources in downstate New York.
For Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation, an expanded MOPR would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions.
On December 19, 2019, FERC required PJM to broadly apply the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage, and all resources owned by vertically-integrated utilities. This greatly expands the breadth and scope of PJM’s MOPR, which is effective as of PJM’s next capacity auction. While FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources.
FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism (under which an entire utility zone would be removed from PJM’s capacity auction along with sufficient resources to support the load in such zone). In response to FERC’s order, PJM submitted a compliance filing on March 18, 2020 wherein PJM proposed tariff language interpreting and implementing FERC's directives, and proposed a schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing.
On April 16, 2020, FERC issued an order largely denying most requests for rehearing of FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing which PJM submitted on June 1, 2020.
On October 15, 2020, FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting PJM’s two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, FERC also accepted PJM’s proposal to condense the schedule of activities leading up to the next capacity auction. In November 2020, PJM announced that it will conduct its next capacity auction beginning on May 19, 2021 and ending on May 25, 2021 and will post the results on June 2, 2021.
Because neither Illinois nor New Jersey have implemented an FRR program in their PJM zones, the MOPR will apply in that next capacity auction to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES, or the New Jersey ZEC program, as applicable, increasing the risk that those units may not clear the capacity market.
Exelon is currently working with PJM and other stakeholders to pursue the FRR option as an alternative to the PJM capacity auction. If Illinois implements the FRR option, Generation’s Illinois nuclear plants could be removed from PJM’s capacity auction and instead supply capacity, and be compensated under the FRR program, which has the potential to mitigate the current economic distress being experienced by Generation's nuclear plants in Illinois, as discussed in Note 7 — Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative and regulatory changes. Whether legislation is needed in New Jersey would depend on how the state chooses to structure an FRR program. Exelon cannot predict whether or when such legislative and regulatory changes can be implemented.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
On February 20, 2020, FERC issued an order rejecting requests to expand NYISO’s version of the MOPR (referred to as buyer-side mitigation rules) beyond its current limited applicability to certain resources in downstate. However, on October 14, 2020, two natural gas-fired generators in New York filed a complaint at FERC seeking to expand the MOPR in NYISO to apply to all resources, new and existing, across the entire NYISO market. Exelon is strenuously opposing expansion of FERC’s MOPR policies in the NYISO market. While it is too early in the proceeding to predict its outcome and there are significant differences between the NYISO and PJM markets that would justify a different result, if FERC follows its MOPR precedent in PJM and applies the MOPR in NYISO broadly as requested in the complaint, Generation’s facilities in NYISO that are receiving ZEC compensation may be at increased risk of not clearing the capacity auction.
If Generation’s state-supported nuclear plants in PJM or NYISO are subjected to the MOPR or equivalent without compensation under an FRR or similar program, it could have a material adverse impact on Exelon's and Generation's financial statements, which Exelon and Generation cannot reasonably estimate at this time.
Operating License Renewals
Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, Generation has been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.
On April 21, 2016, Generation and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a settlement agreement (DOI Settlement) resolving all fish passage issues between the parties.
On April 27, 2018, MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contains numerous conditions, including those relating to reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage, which could have a material, unfavorable impact on Exelon’s and Generation’s financial statements through an increase in capital expenditures and operating costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the conditions are unfair and onerous and in violation of MDE regulations and state, federal, and constitutional law. Generation also requested that FERC defer the issuance of the federal license while these significant state and federal law issues are pending. On February 28, 2019, Generation filed a Petition for Declaratory Order with FERC requesting that FERC issue an order declaring that MDE waived its right to issue a 401 Certification for Conowingo because it failed to timely act on Conowingo’s 401 Certification application and requesting that FERC decline to include the conditions required by MDE in April 2018.
On October 29, 2019, Generation and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. Pursuant to the Offer of Settlement, the parties submitted Proposed License Articles to FERC to be incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act. Among the Proposed License Articles are modifications to river flows to improve aquatic habitat, eel passage improvements, and initiatives to support rare, threatened and endangered wildlife. If FERC approves the Offer of Settlement and incorporates the Proposed License Articles into the new license without modification, then MDE would waive its rights to issue a 401 Certification and Generation would agree, pursuant to a separate agreement with MDE (MDE Settlement), to implement additional environmental protection, mitigation, and enhancement measures over the anticipated 50-year term of the new license. These measures address mussel restoration and other ecological and water quality matters, among other commitments. Exelon’s commitments under the various provisions of the Offer of Settlement and MDE Settlement are not effective unless and until FERC approves the Offer of Settlement, and issues the new license with the Proposed License Articles.
The financial impact of the DOI and MDE Settlements and other anticipated license commitments are estimated to be $11 million to $14 million per year, on average, recognized over the new license term, including capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new license. As of December 31, 2020, $45 million of direct costs associated with Conowingo licensing efforts have been capitalized. Generation's current depreciation provision for Conowingo assumes renewal of the FERC license.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Peach Bottom Units 2 and 3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3, which was approved on March 6, 2020. Peach Bottom Units 2 and 3 are now licensed to operate through 2053 and 2054, respectively. See Note 8 – Property, Plant, and Equipment for additional information regarding the estimated useful life and depreciation provisions for Peach Bottom.
4. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue and no variable consideration for regulated electric and gas tariff sales and regulated transmission services unless noted below.
Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, the Registrants generally recognize revenue in the amount for which they have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
| | | | | | | | | | | | | | |
| Revenue Source | Description | Performance Obligation | Timing of Revenue Recognition | Payment Terms |
| Competitive Power Sales (Exelon and Generation) | Sales of power and other energy-related commodities to wholesale and retail customers across multiple geographic regions through its customer-facing business, Constellation. | Various including the delivery of power (generally delivered over time) and other energy-related commodities such as capacity (generally delivered over time), ZECs, RECs or other ancillary services (generally delivered at a point in time). | Concurrently as power is generated for bundled power sale contracts. (a) | Within the month following delivery to the customer. |
| Competitive Natural Gas Sales (Exelon and Generation) | Sales of natural gas on a full requirement basis or for an agreed upon volume to commercial and residential customers. | Delivery of natural gas to the customer. | Over time as the natural gas is delivered and consumed by the customer. | Within the month following delivery to the customer. |
| Other Competitive Products and Services (Exelon and Generation) | Sales of other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers. | Construction and/or installation of the asset for the customer. | Revenues and associated costs are recognized throughout the contract term using an input method to measure progress towards completion.(b) | Within 30 or 45 days from the invoice date. |
| Regulated Electric and Gas Tariff Sales (Exelon and the Utility Registrants) | Sales of electricity and electricity distribution services (the Utility Registrants) and natural gas and gas distribution services (PECO, BGE, and DPL) to residential, commercial, industrial, and governmental customers through regulated tariff rates approved by state regulatory commissions. | Delivery of electricity and/or natural gas. | Over time (each day) as the electricity and/or natural gas is delivered to customers. Tariff sales are generally considered daily contracts as customers can discontinue service at any time. (c) | Within the month following delivery of the electricity or natural gas to the customer. |
| Regulated Transmission Services (Exelon and the Utility Registrants) | The Utility Registrants provide open access to their transmission facilities to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants pursuant to filed tariffs at cost-based rates approved by FERC. | Various including (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid. | Over time utilizing output methods to measure progress towards completion. (d) | Paid weekly by PJM. |
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(a)Certain contracts may contain limits on the total amount of revenue Exelon and Generation are able to collect over the entire term of the contract. In such cases, Exelon and Generation estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.
(b)The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months.
(c)Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.
(d)Passage of time is used for NITS and access to the wholesale grid and MWHs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services.
Generation incurs incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and were immaterial as of December 31, 2020 and 2019. The Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.
Contract Balances (All Registrants)
Other State Regulatory Matters
Illinois Regulatory Matters
Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through the electric distribution formula rate) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018 through December 31, 2030, the return on equityROE that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency formula rate on or before June 1st each year, with resulting rates effective in January of the following year. The annual update is based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions similar to those in ComEd’s electric distribution formula rate.
During 2018,2020, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:
|
| | | | | | | | | | | |
| Filing Date | Requested Revenue Requirement Increase | Approved Revenue Requirement Increase | | Approved ROE | Approval Date | Rate Effective Date |
| June 1, 2018 | $ | 39 |
| $ | 42 |
| (a) | 8.69 | % | December 4, 2018 | January 1, 2019 |
237
_________ | |
(a) | ComEd’s 2018 approved revenue requirement above reflects an increase of $41 million for the initial year revenue requirement for 2018 and 2019 and an increase of $1 million related to the annual reconciliation for 2017. The revenue requirement for 2018 and 2019 and the annual reconciliation for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.52% inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. |
Maryland Regulatory Matters
Cash Working Capital Order (Exelon and BGE). On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its ProviderTable of Last Resort service, also known as Standard Offer Service (SOS), as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover its SOS-related costs. The Administrative Charge is comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which acts as a proxy for retail suppliers’ costs. The Commission accepted BGE's positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a return on the SOS. The Commission ruled that the level of the administrative adjustment will be determined in BGE’s next rate case. Subsequently, the MDPSC Staff and residential consumer advocate sought clarification and appealed the amount of return awarded to BGE on the SOS. The appeal currently resides with the Maryland Court of Special Appeals. BGE cannot predict the outcome of this appeal.Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and natural gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. See AMI programs in the Regulatory Assets and Liabilities section below for additional information.
As part of the 2015 electric and natural gas distribution rate case filed on November 6, 2015, BGE sought recovery of its smart grid initiative costs, supported by evidence demonstrating that BGE had, in fact, implemented a cost-
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
beneficial advanced metering system. On June | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Filing Date | | Requested Revenue Requirement Increase | | Approved Revenue Requirement Increase | | Approved ROE | | Approval Date | | Rate Effective Date |
| May 21, 2020 | | $ | 48 | | | $ | 48 | | (a) | 8.38 | % | | December 2, 2020 | | January 1, 2021 |
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(a)ComEd’s 2021 approved revenue requirement above reflects an increase of $45 million for the initial year revenue requirement for 2021 and an increase of $3 2016, the MDPSC issued an order concluding that the smart grid initiative overall is cost beneficial to its customers. However, the June 3rd order contained several cost disallowances and adjustments including disallowances of certain program and meter installation costs and denial of recovery of any return on unrecovered costs for non-AMI meters replaced under the program. BGE and the residential consumer advocate subsequently both filed a petition for rehearing of the June 3rd order. On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustmentsmillion related to the smart grid initiative.
Asannual reconciliation for 2019. The revenue requirement for 2021 provides for a combined resultweighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.28% inclusive of an allowed ROE of 8.38%, reflecting the MDPSC orders in BGE's 2015 electricmonthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for 2019 provides for a weighted average debt and natural gas distributionequity return on the energy efficiency regulatory asset and rate base rate case, BGE recorded a $52 million charge in June 2016 to Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income reducing certain6.56% inclusive of an allowed ROE of 8.96%, which includes an upward performance adjustment that can either increase or decrease the ROE. See table below for ComEd's regulatory assets and other long-lived assets and reclassified $56 million of legacy meter costs from Property, plant and equipment, net toassociated with its energy efficiency formula rate.
Maryland Regulatory assets in Exelon's and BGE's Consolidated Balance Sheets. In BGE’s 2018 natural gas distribution base rate case, the MDPSC allowed BGE to recover the gas portion of the post-test year regulatory asset, including a return thereon, over three years. The electric portion of the same regulatory asset will be addressed in BGE’s next electric distribution base rate case. Matters
The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In 2013, legislation in Maryland was signed into law to establish a mechanism, separate from base rate proceedings, for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects incurred after June 1, 2013. The monthly surcharge and infrastructure replacement costs must be approved by the MDPSC and are subject to a cap and require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution base rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation.
On December 1, 2017 (as amended on January 22, 2018), BGE filed an application with the MDPSC seeking approval for a new gas infrastructure replacement plan and associated surcharge, effective for the five-year period from 2019 through 2023. On May 30, 2018, the MDPSC approved with modifications a new infrastructure plan and associated surcharge, subject to BGE's acceptance of the Order. On June 1, 2018, BGE accepted the MDPSC Order and the associated surcharge will bebecame effective in rates beginning in January 2019. The new five-year plan calls for capital expenditures over the 2019-2023 timeframe of $732 million with an associated revenue requirement of $200 million.
DistrictCash Working Capital Order (Exelon and BGE). On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its POLR service, also known as SOS, as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover its SOS-related costs. The Administrative Charge is comprised of Columbia Regulatory Matters
District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco).The District of Columbia government enacted on a permanent basis (effective July 11, 2017) legislation to amend the Electric Company Infrastructure Improvement Financing Act of 2014 (as amended) (the Infrastructure Improvement Financing Act) to authorize the District of Columbia Power Line Undergrounding (DC PLUG) initiative, a projected six year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the projectfive components: CWC, uncollectibles, incremental costs, funded by Pepco and $250 million funded by the District of Columbia.
The $250 million of project costs funded by Pepco will earn a return, and be recovered throughan administrative adjustment, which acts as a volumetric surchargeproxy for retail suppliers’ costs. The MDPSC accepted BGE's positions on the electric billrecovery of Pepco's customers in the DistrictCWC and pass-through recovery of Columbia.
BGE’s actual uncollectibles and incremental costs. The $250 million of project costs funded by the District of Columbia will come from two sources. Project costs of $187.5 million will be funded through a charge assessed on Pepco by the District of Columbia; Pepco will recover this charge from customers through a volumetric distribution rider. The remaining costs up to $62.5 million are to be funded by the existing capital projects program of the District Department of Transportation (DDOT). Ownership and responsibility for the operation and maintenance of assets funded by the District of Columbia will be transferred to Pepco for a nominal amount upon completion, and Pepco will not recover or earnorder also grants BGE a return on the costSOS. Subsequently, the MDPSC Staff and residential consumer advocate sought clarification and appealed the amount of these assets.
In accordance withreturn awarded to BGE on the Infrastructure Improvement Financing Act, Pepco filed an application for approvalSOS. On July 27, 2020, the Maryland Court of Special Appeals affirmed the first two-year plan incircuit court’s judgment affirming the DC PLUG initiative (the First Biennial Plan) on July 3, 2017. Pepco will then be required to make two additional applications. On November 9, 2017,MDPSC’s decision. No party appealed the DCPSC issued an order approving the First Biennial Plan and the application for a financing order. Pursuant to that order, Pepco is obligated to pay $187.5 milliondecision to the DistrictMaryland Court of Columbia overAppeals. Also, in BGE’s 2019 electric and gas distribution base rate proceeding, the six-year project term,MDPSC established a normalized administrative adjustment. However, a group of which it expectselectric suppliers appealed the MDPSC’s decision to pay $30 million in 2019. Pepco recorded
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
an obligation and offsetting regulatory asset in November. Ratesthe Circuit Court for Baltimore City. BGE cannot predict the DC PLUG initiative went into effect on February 7, 2018.outcome of this appeal.
New Jersey Regulatory Matters
ACE Infrastructure Investment Program Filing (Exelon, PHI, and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s Infrastructure Investment Program (IIP)IIP proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement.
Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE filed an application with the NJBPU as was required seeking approval to deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consists of estimated costs totaling $220 million, with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that involves the installation of an integrated system of smart meters for all customers accompanied by the requisite communications facilities and data management systems. ACE is seeking authority to recover these estimated investments through a combination of the ACE IIP rider mechanism and future distribution base rates. ACE currently expects a decision in this matter in the secondthird quarter of 20192021 but cannot predict if the NJBPU will approve the application as filed.
Combined Notes to Consolidated Tax Adjustment (Exelon, PHI and ACE). The Consolidated Tax Adjustment (CTA) is a ratemaking policy that requires utilities that are part of a consolidated tax group toFinancial Statements
(Dollars in millions, except per share with customers the tax benefits that came from losses at unregulated affiliates through a reduction in rate base. After opening a generic proceeding to review the policy, in 2014, the NJBPU issued a decision which retained the CTA, but in a modified format that significantly reduced the impact of the CTA to ACE. On September 18, 2017, the Appellate Division of the Superior Court of New Jersey reversed the NJBPU’s decision in adopting the revised CTA policy and held that NJBPU’s actions related to the CTA constituted a rulemaking that should have been undertaken pursuant to the requirements of the Administrative Procedures Act. The Court did not address the merits of the CTA methodology itself. The NJBPU issued a proposed rule for comment, consistent with the requirements of the Administrative Procedures Act. On January 17, 2019, the NJBPU adopted the proposed CTA regulations, which do not have a material impact on ACE. The CTA regulations will be sent to the Office of Administrative Law for publication in the New Jersey Register, which is expected on or before March 4, 2019.data unless otherwise noted)
Note 3 — Regulatory Matters
New Jersey Clean Energy Legislation (Exelon, PHI, and ACE).On May 23, 2018, the Governor of New Jersey signed newenacted legislation effective immediately, that established and modified New Jersey’s clean energy and energy efficiency programs and solar and renewable energy portfolio standards. The new legislation expands the state's renewable portfolio standard to require that 50% of electric generation sold be from renewable energy sources by 2030; modifies the New Jersey solar renewable energy portfolio standard to require that 5.1% of electric generation sold in New Jersey be from solar electric power by 2021; lowers the solar alternative compliance payment amount starting in 2019 and requires the NJBPU to adopt rules to replace the current solar renewable energy credit program; and requires the NJBPU to increase its offshore wind energy credit program to 3,500 MW. The new legislation further imposes an energy efficiency standard that each electric public utility will be required to reduce annual usage by 2% and provides for utilities to annually file for recovery of the costs of the programs, including the revenue impact of sales losses resulting from the programs. The NJBPU is required to initiate a study to determine the savings targets for each public utility, to adopt other rules regarding the programs, and to approve energy efficiency and peak demand reduction programs for each utility. The new legislation also requires the NJBPU to conduct an energy storage analysis including the potential costs and benefits and to initiate a proceeding to establish a goal of achieving 2,000 MW of energy storage by 2030; requires the utilities to conduct a study on voltage optimization on their distribution system; and requires the NJBPU to establish a community solar program to permit customers to participate in a solar project that is not located on the customer’s property which the NJBPU issued regulations on January 17, 2019.
RPS. On the same day, the Governor of New Jersey also signed newenacted legislation effective immediately, that will establishestablished a ZEC program providingthat provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Electric distribution utilities in New Jersey, including ACE, will be authorized to collectbegan collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the utility’s procurement of the ZECs.ZECs effective April 18, 2019. See Generation Regulatory Matters below for additional information.
Other Federal Regulatory Matters
Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE).On December 13, 2016 (as(and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. ComEd, Pepco, DPL and ACE had similar transmission-related income tax regulatory liabilities and assets also requiring FERC
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
approval. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. FERC’s rejection order focused onIn the lackfourth quarter of timeliness of BGE’s request to recover amounts that would have been previously amortized but indicated that ongoing recovery of certain2017, ComEd, BGE, Pepco, DPL, and ACE fully impaired their associated transmission-related income tax regulatory assets would provide for a more accurate revenue requirement. Based on FERC’s order, management of each company concluded that the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery was no longer probable of recovery. As a result, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE recorded the following charges to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017, reducing their associated transmission-related income tax regulatory assets. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula and, thus, are not impacted by BGE’s November 16, 2017 FERC order. See above for additional information regarding PECO's transmission formula rate filing.
|
| | | |
| | For the year ended December 31, 2017 |
| Exelon | $ | 35 |
|
| ComEd | 3 |
|
| BGE | 5 |
|
| PHI | 27 |
|
| Pepco | 14 |
|
| DPL | 6 |
|
| ACE | 7 |
|
On December 18, 2017, BGE filed for clarification and rehearing of FERC’s order, still seeking full recovery of its existing transmission-related income tax regulatory asset amounts, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery. On February 27, 2018 (and updated on March 26, 2018), BGE submitted a letter to FERC advising that the lower federal corporate income tax rate effective January 1, 2018 provided for in the TCJA will be reflected in BGE’s annual formula rate update effective June 1, 2018, but that the deferred income tax benefits will not be passed back to customers unless BGE’s formula rate is revised to provide for pass back and recovery of transmission-related income tax-related regulatory liabilities and assets.amortized.
On February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to facilitate passing back to customers ongoing annual TCJA tax savings and to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.
On September 7, 2018, FERC issued orders rejecting 1) BGE’s December 18,rehearing request of FERC's November 16, 2017 request for rehearingorder and clarification and ComEd's, Pepco's, DPL's and ACE's2) the February 23, 2018 (as amended on July 9, 2018) filings, again citingfiling by ComEd, Pepco, DPL, and ACE for similar recovery.
On November 2, 2018, BGE filed an appeal of FERC's September 7, 2018 order to the lackU.S. Court of timelinessAppeals for the D.C. Circuit. On March 27, 2020, the U.S. Court of Appeals for the requests to recover amounts that would have been previously amortized, but indicating that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement. The orders did not address the remittance of TCJA transmission-related income tax regulatory liabilities, but rather referenced FERC’s separate Notice of Inquiry of such amounts issued on March 15, 2018.D.C. Circuit Court denied BGE’s November 2, 2018 appeal.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted new filings to recover ongoing non-TCJA amortization amounts and refundcredit TCJA transmission-related income tax regulatory liabilities to customers for the prospective period starting on October 1, 2018. On April 26, 2019, FERC issued deficiency letters requesting additional information on November 21,an order accepting ComEd's, BGE's, Pepco's, DPL's, and ACE's October 1, 2018 filings, effective October 1, 2018, subject to refund and January 28, 2019.established hearing and settlement judge procedures. On April 24, 2020, ComEd, BGE, Pepco, DPL, ACE, and ACE respondedother parties filed a settlement agreement with FERC, which FERC approved on September 24, 2020. The settlement agreement provides for the recovery of ongoing transmission-related income tax regulatory assets and establishes the amount and amortization period for excess deferred income taxes resulting from TCJA. The settlement resulted in a reduction to the November 21, 2018 deficiency letter on November 29, 2018 but cannot predict the outcome of these FERC proceedings. If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPLOperating revenues and ACE would record additional chargesan offsetting reduction to Income tax expense which could be up to approximately $76 million, $51 million, $15 million, $10 million, $3 million, $5 million and $2 million, respectively, as of December 31, 2018.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
On October 9, 2018, ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order, still seeking full recovery of their existing transmission-related income tax regulatory asset amounts, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery. ComEd, Pepco, DPL, and ACE cannot predict the outcome of this rehearing request. On November 2, 2018, BGE filed an appeal of FERC’s September 7, 2018 order to the Court of Appeals for the D.C. Circuit.
PJM Transmission Rate Design (All Registrants). On June 15, 2016, several parties, including the Utility Registrants, filed a proposed settlement with FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. The settlement included provisions for monthly credits or charges related to the periods prior to January 1, 2016 that are expected to be refunded or recovered through PJM wholesale transmission rates through December 2025.
On May 31, 2018, FERC issued an order approving the settlement and directed PJM to adjust wholesale transmission rates within 30 days. Pursuant to the order, similar charges for the period January 1, 2016 through June 30, 2018 will also be refunded or recovered through PJM wholesale transmission rates over the subsequent 12-month period. PJM commenced billing the refunds and charges associated with this settlement in August 2018. The Utility Registrants expect to refund or recover these settlement amounts through prospective electric distribution customer rates. On July 2, 2018, several parties filed petitions for rehearing or clarification.
Pursuant to the FERC approval of the settlement and the expected refund or recovery of the associated amounts from electric distribution customers, in the second quarter of 2018 and as adjusted in the third quarter of 2018, the Utility Registrants recorded the following payables to/receivables from PJM and related regulatory assets/liabilities. Generation recorded a $41 million net payable to PJM and a pre-tax charge within Purchased power and fuel expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
|
| | | | | | | | | | | | |
| | PJM Receivable | PJM Payable | Regulatory Asset | Regulatory Liability |
| Exelon | $ | 220 |
| $ | 176 |
| $ | 136 |
| $ | 221 |
|
Generation(a) | — |
| 41 |
| — |
| — |
|
| ComEd | 122 |
| — |
| — |
| 122 |
|
| PECO | 85 |
| — |
| — |
| 85 |
|
| BGE | — |
| 51 |
| 51 |
| — |
|
| PHI | 13 |
| 84 |
| 85 |
| 14 |
|
| Pepco | — |
| 84 |
| 84 |
| — |
|
| DPL | 10 |
| — |
| — |
| 10 |
|
| ACE | 3 |
| — |
| 1 |
| 4 |
|
__________
| |
(a) | Does not include an offsetting receivable from New Jersey Utilities of $16 million as of December 31, 2018. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
2020.
Regulatory Assets and Liabilities
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE as of December 31, 20182020 and December 31, 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory assets | | | | | | | | | | | | | | | |
| Pension and OPEB | $ | 3,010 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Pension and OPEB - merger related | 1,014 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred income taxes | 715 | | | 0 | | | 705 | | | 0 | | | 10 | | | 10 | | | 0 | | | 0 | |
| AMI programs - deployment costs | 174 | | | 0 | | | 0 | | | 109 | | | 65 | | | 35 | | | 30 | | | 0 | |
| AMI programs - legacy meters | 219 | | | 90 | | | 0 | | | 37 | | | 92 | | | 68 | | | 24 | | | 0 | |
| | | | | | | | | | | | | | | |
| Electric distribution formula rate annual reconciliations | (14) | | | (14) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Electric distribution formula rate significant one-time events | 117 | | | 117 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Energy efficiency costs | 982 | | | 982 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Fair value of long-term debt | 598 | | | 0 | | | 0 | | | 0 | | | 478 | | | 0 | | | 0 | | | 0 | |
| Fair value of PHI's unamortized energy contracts | 328 | | | 0 | | | 0 | | | 0 | | | 328 | | | 0 | | | 0 | | | 0 | |
| Asset retirement obligations | 135 | | | 92 | | | 21 | | | 18 | | | 4 | | | 3 | | | 0 | | | 1 | |
| MGP remediation costs | 285 | | | 271 | | | 10 | | | 4 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Renewable energy | 301 | | | 301 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Electric energy and natural gas costs | 95 | | | 0 | | | 0 | | | 23 | | | 72 | | | 37 | | | 5 | | | 30 | |
| Transmission formula rate annual reconciliations | 5 | | | 0 | | | 0 | | | 2 | | | 3 | | | 0 | | | 2 | | | 1 | |
| Energy efficiency and demand response programs | 572 | | | 0 | | | 0 | | | 289 | | | 283 | | | 203 | | | 80 | | | 0 | |
| | | | | | | | | | | | | | | |
| Under-recovered revenue decoupling | 113 | | | 0 | | | 0 | | | 20 | | | 93 | | | 93 | | | 0 | | | 0 | |
| Stranded costs | 25 | | | 0 | | | 0 | | | 0 | | | 25 | | | 0 | | | 0 | | | 25 | |
| Removal costs | 701 | | | 0 | | | 0 | | | 107 | | | 594 | | | 151 | | | 105 | | | 339 | |
| DC PLUG charge | 100 | | | 0 | | | 0 | | | 0 | | | 100 | | | 100 | | | 0 | | | 0 | |
| Deferred storm costs | 50 | | | 0 | | | 0 | | | 0 | | | 50 | | | 5 | | | 4 | | | 41 | |
| COVID-19 | 81 | | | 22 | | | 38 | | | 10 | | | 11 | | | 7 | | | 4 | | | 0 | |
| Under-recovered credit loss expense | 107 | | | 89 | | | 0 | | | 0 | | | 18 | | | 0 | | | 0 | | | 18 | |
| Other | 274 | | | 78 | | | 27 | | | 30 | | | 147 | | | 72 | | | 26 | | | 15 | |
| Total regulatory assets | 9,987 | | | 2,028 | | | 801 | | | 649 | | | 2,373 | | | 784 | | | 280 | | | 470 | |
| Less: current portion | 1,228 | | | 279 | | | 25 | | | 168 | | | 440 | | | 214 | | | 58 | | | 75 | |
| Total noncurrent regulatory assets | $ | 8,759 | | | $ | 1,749 | | | $ | 776 | | | $ | 481 | | | $ | 1,933 | | | $ | 570 | | | $ | 222 | | | $ | 395 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2018 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory assets | | | | | | | | | | | | | | | |
| Pension and other postretirement benefits | $ | 2,553 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Pension and other postretirement benefits - Merger related | 1,266 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Deferred income taxes | 414 |
| | — |
| | 404 |
| | — |
| | 10 |
| | 10 |
| | — |
| | — |
|
| AMI programs - Deployment Costs | 202 |
| | — |
| | — |
| | 113 |
| | 89 |
| | 50 |
| | 39 |
| | — |
|
| AMI programs - Legacy Meters | 328 |
| | 136 |
| | 24 |
| | 48 |
| | 120 |
| | 90 |
| | 30 |
| | — |
|
| AMI programs - Post-test year costs | 32 |
| | — |
| | — |
| | 32 |
| | — |
| | — |
| | — |
| | — |
|
| Electric distribution formula rate annual reconciliations | 158 |
| | 158 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Electric distribution formula rate significant one-time events | 81 |
| | 81 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Energy efficiency costs | 472 |
| | 472 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Fair value of long-term debt | 702 |
| | — |
| | — |
| | — |
| | 569 |
| | — |
| | — |
| | — |
|
| Fair value of PHI's unamortized energy contracts | 561 |
| | — |
| | — |
| | — |
| | 561 |
| | — |
| | — |
| | — |
|
| Asset retirement obligations | 118 |
| | 79 |
| | 22 |
| | 16 |
| | 1 |
| | 1 |
| | — |
| | — |
|
| MGP remediation costs | 326 |
| | 309 |
| | 17 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Renewable energy | 249 |
| | 249 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Electric Energy and Natural Gas Costs | 193 |
| | — |
| | 49 |
| | 51 |
| | 93 |
| | 84 |
| | — |
| | 9 |
|
| Transmission formula rate annual reconciliations | 41 |
| | 6 |
| | — |
| | 4 |
| | 31 |
| | 10 |
| | 14 |
| | 7 |
|
| Energy efficiency and demand response programs | 545 |
| | — |
| | 1 |
| | 289 |
| | 255 |
| | 188 |
| | 67 |
| | — |
|
| Merger integration costs | 42 |
| | — |
| | — |
| | 3 |
| | 39 |
| | 18 |
| | 11 |
| | 10 |
|
| Under-recovered revenue decoupling | 59 |
| | — |
| | — |
| | 2 |
| | 57 |
| | 57 |
| | — |
| | — |
|
| Securitized stranded costs | 50 |
| | — |
| | — |
| | — |
| | 50 |
| | — |
| | — |
| | 50 |
|
| Removal costs | 564 |
| | — |
| | — |
| | — |
| | 564 |
| | 158 |
| | 97 |
| | 309 |
|
| DC PLUG charge | 159 |
| | — |
| | — |
| | — |
| | 159 |
| | 159 |
| | — |
| | — |
|
| Deferred storm costs | 41 |
| | — |
| | — |
| | — |
| | 41 |
| | 9 |
| | 4 |
| | 28 |
|
| Other | 303 |
| | 110 |
| | 24 |
| | 17 |
| | 162 |
| | 79 |
| | 28 |
| | 13 |
|
| Total regulatory assets | 9,459 |
| | 1,600 |
| | 541 |
| | 575 |
| | 2,801 |
| | 913 |
| | 290 |
| | 426 |
|
| Less: current portion | 1,222 |
| | 293 |
| | 81 |
| | 177 |
| | 489 |
| | 270 |
| | 59 |
| | 40 |
|
| Total noncurrent regulatory assets | $ | 8,237 |
| | $ | 1,307 |
| | $ | 460 |
| | $ | 398 |
| | $ | 2,312 |
| | $ | 643 |
| | $ | 231 |
| | $ | 386 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory liabilities | | | | | | | | | | | | | | | |
| Deferred income taxes | $ | 4,502 | | | $ | 2,205 | | | $ | 0 | | | $ | 1,001 | | | $ | 1,296 | | | $ | 621 | | | $ | 404 | | | $ | 271 | |
| Nuclear decommissioning | 3,016 | | | 2,541 | | | 475 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Removal costs | 1,649 | | | 1,482 | | | 0 | | | 47 | | | 120 | | | 20 | | | 100 | | | 0 | |
| Electric energy and natural gas costs | 175 | | | 34 | | | 97 | | | 6 | | | 38 | | | 24 | | | 10 | | | 4 | |
| Transmission formula rate annual reconciliations | 52 | | | 2 | | | 12 | | | 0 | | | 38 | | | 23 | | | 9 | | | 6 | |
| Renewable portfolio standards costs | 427 | | | 427 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Stranded costs | 24 | | | 0 | | | 0 | | | 0 | | | 24 | | | 0 | | | 0 | | | 24 | |
| Other | 221 | | | 1 | | | 40 | | | 85 | | | 59 | | | 2 | | | 17 | | | 13 | |
| Total regulatory liabilities | 10,066 | | | 6,692 | | | 624 | | | 1,139 | | | 1,575 | | | 690 | | | 540 | | | 318 | |
| Less: current portion | 581 | | | 289 | | | 121 | | | 30 | | | 137 | | | 46 | | | 47 | | | 44 | |
| Total noncurrent regulatory liabilities | $ | 9,485 | | | $ | 6,403 | | | $ | 503 | | | $ | 1,109 | | | $ | 1,438 | | | $ | 644 | | | $ | 493 | | | $ | 274 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2018 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory liabilities | | | | | | | | | | | | | | | |
| Deferred income taxes | $ | 5,228 |
| | $ | 2,394 |
| | $ | — |
| | $ | 1,132 |
| | $ | 1,702 |
| | $ | 798 |
| | $ | 510 |
| | $ | 394 |
|
| Nuclear decommissioning | 2,606 |
| | 2,217 |
| | 389 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Removal costs | 1,547 |
| | 1,368 |
| | — |
| | 52 |
| | 127 |
| | 20 |
| | 107 |
| | — |
|
| Electric Energy and Natural Gas Costs | 294 |
| | 137 |
| | 132 |
| | 6 |
| | 19 |
| | — |
| | 18 |
| | 1 |
|
| Other | 528 |
| | 227 |
| | 75 |
| | 79 |
| | 100 |
| | 11 |
| | 30 |
| | 25 |
|
| Total regulatory liabilities | 10,203 |
| | 6,343 |
| | 596 |
| | 1,269 |
|
| 1,948 |
| | 829 |
| | 665 |
| | 420 |
|
| Less: current portion | 644 |
| | 293 |
| | 175 |
| | 77 |
| | 84 |
| | 7 |
| | 59 |
| | 18 |
|
| Total noncurrent regulatory liabilities | $ | 9,559 |
| | $ | 6,050 |
| | $ | 421 |
| | $ | 1,192 |
|
| $ | 1,864 |
| | $ | 822 |
| | $ | 606 |
| | $ | 402 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2019 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory assets | | | | | | | | | | | | | | | |
| Pension and OPEB | $ | 2,784 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | — | | | $ | 0 | | | $ | 0 | |
| Pension and OPEB - merger related | 1,138 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred income taxes | 528 | | | 0 | | | 518 | | | 0 | | | 10 | | | 10 | | | 0 | | | 0 | |
| AMI programs - deployment costs | 207 | | | 0 | | | 0 | | | 129 | | | 78 | | | 43 | | | 35 | | | 0 | |
| AMI programs - legacy meters | 276 | | | 113 | | | 12 | | | 45 | | | 106 | | | 79 | | | 27 | | | 0 | |
| Electric distribution formula rate annual reconciliations | 34 | | | 34 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Electric distribution formula rate significant one-time events | 66 | | | 66 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Energy efficiency costs | 746 | | | 746 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Fair value of long-term debt | 650 | | | 0 | | | 0 | | | 0 | | | 523 | | | 0 | | | 0 | | | 0 | |
| Fair value of PHI's unamortized energy contracts | 443 | | | 0 | | | 0 | | | 0 | | | 443 | | | 0 | | | 0 | | | 0 | |
| Asset retirement obligations | 127 | | | 85 | | | 23 | | | 16 | | | 3 | | | 2 | | | 0 | | | 1 | |
| MGP remediation costs | 302 | | | 287 | | | 11 | | | 4 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Renewable energy | 301 | | | 301 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Electric energy and natural gas costs | 110 | | | 0 | | | 6 | | | 36 | | | 68 | | | 43 | | | 5 | | | 20 | |
| Transmission formula rate annual reconciliations | 11 | | | 0 | | | 0 | | | 1 | | | 10 | | | 1 | | | 2 | | | 7 | |
| Energy efficiency and demand response programs | 572 | | | 0 | | | 0 | | | 303 | | | 269 | | | 196 | | | 73 | | | 0 | |
| Merger integration costs | 32 | | | 0 | | | 0 | | | 2 | | | 30 | | | 15 | | | 8 | | | 7 | |
| Under-recovered revenue decoupling | 37 | | | 0 | | | 0 | | | 8 | | | 29 | | | 29 | | | 0 | | | 0 | |
| Stranded costs | 37 | | | 0 | | | 0 | | | 0 | | | 37 | | | 0 | | | 0 | | | 37 | |
| Removal costs | 641 | | | 0 | | | 0 | | | 67 | | | 574 | | | 152 | | | 100 | | | 324 | |
| DC PLUG charge | 126 | | | 0 | | | 0 | | | 0 | | | 126 | | | 126 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | |
| Other | 337 | | | 129 | | | 25 | | | 26 | | | 167 | | | 76 | | | 24 | | | 29 | |
| Total regulatory assets | 9,505 | | | 1,761 | | | 595 | | | 637 | | | 2,473 | | | 772 | | | 274 | | | 425 | |
| Less: current portion | 1,170 | | | 281 | | | 41 | | | 183 | | | 412 | | | 188 | | | 52 | | | 57 | |
| Total noncurrent regulatory assets | $ | 8,335 | | | $ | 1,480 | | | $ | 554 | | | $ | 454 | | | $ | 2,061 | | | $ | 584 | | | $ | 222 | | | $ | 368 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2019 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory liabilities | | | | | | | | | | | | | | | |
| Deferred income taxes | $ | 4,944 | | | $ | 2,297 | | | $ | 0 | | | $ | 1,089 | | | $ | 1,558 | | | $ | 725 | | | $ | 477 | | | $ | 356 | |
| Nuclear decommissioning | 3,102 | | | 2,622 | | | 480 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Removal costs | 1,621 | | | 1,435 | | | 0 | | | 58 | | | 128 | | | 20 | | | 108 | | | 0 | |
| | | | | | | | | | | | | | | |
| Electric energy and natural gas costs | 109 | | | 45 | | | 56 | | | 0 | | | 8 | | | 0 | | | 8 | | | 0 | |
| Transmission formula rate annual reconciliations | 34 | | | 6 | | | 28 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | |
| Other | 582 | | | 337 | | | 37 | | | 81 | | | 83 | | | 9 | | | 18 | | | 26 | |
| Total regulatory liabilities | 10,392 | | | 6,742 | | | 601 | | | 1,228 | | | 1,777 | | | 754 | | | 611 | | | 382 | |
| Less: current portion | 406 | | | 200 | | | 91 | | | 33 | | | 70 | | | 8 | | | 37 | | | 25 | |
| Total noncurrent regulatory liabilities | $ | 9,986 | | | $ | 6,542 | | | $ | 510 | | | $ | 1,195 | | | $ | 1,707 | | | $ | 746 | | | $ | 574 | | | $ | 357 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2017 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory assets | | | | | | | | | | | | | | | |
| Pension and other postretirement benefits | $ | 2,455 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Pension and other postretirement benefits - Merger related | 1,393 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Deferred income taxes | 306 |
| | — |
| | 297 |
| | — |
| | 9 |
| | 9 |
| | — |
| | — |
|
| AMI programs - Deployment costs | 385 |
| | — |
| | — |
| | 129 |
| | 101 |
| | 58 |
| | 43 |
| | — |
|
| AMI programs - Legacy meters | 223 |
| | 155 |
| | 36 |
| | 53 |
| | 134 |
| | 100 |
| | 34 |
| | — |
|
| AMI programs - Post-test year costs | 32 |
| | — |
| | — |
| | 32 |
| | — |
| | — |
| | — |
| | — |
|
| Electric distribution formula rate annual reconciliations | 186 |
| | 186 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Electric distribution formula rate significant one-time events | 58 |
| | 58 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Energy efficiency costs | 166 |
| | 166 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Fair value of long-term debt | 758 |
| | — |
| | — |
| | — |
| | 619 |
| | — |
| | — |
| | — |
|
| Fair value of PHI's unamortized energy contracts | 750 |
| | — |
| | — |
| | — |
| | 750 |
| | — |
| | — |
| | — |
|
| Asset retirement obligations | 109 |
| | 73 |
| | 22 |
| | 14 |
| | — |
| | — |
| | — |
| | — |
|
| MGP remediation costs | 295 |
| | 273 |
| | 22 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Renewable energy | 258 |
| | 256 |
| | — |
| | — |
| | 2 |
| | — |
| | 1 |
| | 1 |
|
| Electric energy and natural gas costs | 47 |
| | — |
| | 1 |
| | 16 |
| | 30 |
| | 8 |
| | 7 |
| | 15 |
|
| Transmission formula rate annual reconciliations | 35 |
| | 6 |
| | — |
| | 7 |
| | 22 |
| | 3 |
| | 8 |
| | 11 |
|
| Energy efficiency and demand response programs | 596 |
| | — |
| | 1 |
| | 285 |
| | 310 |
| | 229 |
| | 81 |
| | — |
|
| Merger integration costs | 45 |
| | — |
| | — |
| | 6 |
| | 39 |
| | 20 |
| | 10 |
| | 9 |
|
| Under-recovered revenue decoupling | 55 |
| | — |
| | — |
| | 14 |
| | 41 |
| | 38 |
| | 3 |
| | — |
|
| Securitized stranded costs | 79 |
| | — |
| | — |
| | — |
| | 79 |
| | — |
| | — |
| | 79 |
|
| Removal costs | 529 |
| | — |
| | — |
| | — |
| | 529 |
| | 150 |
| | 93 |
| | 286 |
|
| DC PLUG charge | 190 |
| | — |
| | — |
| | — |
| | 190 |
| | 190 |
| | — |
| | — |
|
| Deferred storm costs | 27 |
| | — |
| | — |
| | — |
| | 27 |
| | 7 |
| | 5 |
| | 15 |
|
| Other | 311 |
| | 106 |
| | 31 |
| | 15 |
| | 165 |
| | 79 |
| | 29 |
| | 14 |
|
| Total regulatory assets | 9,288 |
| | 1,279 |
| | 410 |
| | 571 |
|
| 3,047 |
| | 891 |
| | 314 |
| | 430 |
|
| Less: current portion | 1,267 |
| | 225 |
| | 29 |
| | 174 |
| | 554 |
| | 213 |
| | 69 |
| | 71 |
|
| Total noncurrent regulatory assets | $ | 8,021 |
| | $ | 1,054 |
| | $ | 381 |
| | $ | 397 |
|
| $ | 2,493 |
| | $ | 678 |
| | $ | 245 |
| | $ | 359 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2017 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Regulatory liabilities | | | | | | | | | | | | | | | |
| Deferred income taxes | $ | 5,241 |
| | $ | 2,479 |
| | $ | — |
| | $ | 1,032 |
| | $ | 1,730 |
| | $ | 809 |
| | $ | 510 |
| | $ | 411 |
|
| Nuclear decommissioning | 3,064 |
| | 2,528 |
| | 536 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Removal costs | 1,573 |
| | 1,338 |
| | — |
| | 105 |
| | 130 |
| | 20 |
| | 110 |
| | — |
|
| Electric Energy and Natural Gas Costs | 111 |
| | 47 |
| | 60 |
| | — |
| | 4 |
| | — |
| | 1 |
| | 3 |
|
| Other | 399 |
| | 185 |
| | 94 |
| | 26 |
| | 64 |
| | 3 |
| | 14 |
| | 8 |
|
| Total regulatory liabilities | 10,388 |
| | 6,577 |
| | 690 |
| | 1,163 |
|
| 1,928 |
| | 832 |
| | 635 |
| | 422 |
|
| Less: current portion | 523 |
| | 249 |
| | 141 |
| | 62 |
| | 56 |
| | 3 |
| | 42 |
| | 11 |
|
| Total noncurrent regulatory liabilities | $ | 9,865 |
| | $ | 6,328 |
| | $ | 549 |
| | $ | 1,101 |
|
| $ | 1,872 |
| | $ | 829 |
| | $ | 593 |
| | $ | 411 |
|
Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.
|
| | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
Pension and Other Postretirement BenefitsOPEB | Primarily reflects the Utility Registrants' portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and other postretirement benefitOPEB plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets. | The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and other postretirementOPEB cost recognition policies. See Note 16 –15 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. | No |
Pension and Other Postretirement BenefitsOPEB - Merger Relatedmerger related | The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and other postretirementOPEB cost recognition policies. See Note 16 –15 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. | Legacy Constellation - 2038 Legacy PHI - 2032 | No |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| Deferred income taxes | | | |
Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
Deferred Income Taxes | Deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA. These amounts include transmission-related regulatory liabilities that require FERC approval separate from the transmission formula rate. See Transmission-Related Income Tax Regulatory Assets section above for additional information. | Over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules. | No |
| | | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
AMI Programsprograms - Deployment Costsdeployment costs
| Installation costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters. | BGE - 2026 Pepco - 2027 DPL - 2030 | Yes |
AMI Programsprograms - Legacy Meterslegacy meters | Early retirement costs of legacy meters. | ComEd - 2028 PECO - 2020
BGE - 20282026 Pepco - 2027 DPL - 2030 | ComEd, Pepco (District of Columbia), DPL (Delaware) - Yes PECO, BGE, Pepco (Maryland), DPL (Maryland) - No
|
AMI Programs - Post-test year incremental costs | Post-test year incremental program deployment costs of smart meters. As of December 31, 2018 and 2017, the portion of BGE's regulatory asset related to gas and electric costs was $10 million and $22 million, respectively.
| BGE (gas) - 2021
BGE (electric) - Not currently being recovered.
| BGE (gas) - Yes
BGE (electric) - No
|
Electric distribution formula rate annual reconciliations
| Under-recoveriesUnder/(Over)-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which is updated annually with rates effective on January 1st.
| 2020
2022
| Yes |
Electric distribution formula rate significant one-time events
| Under-recoveries of electricDeferred distribution service costs related to ComEd's significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event. | 20222024 | Yes |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
Energy efficiency costs
| | | |
Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
Energy Efficiency Costs
| CostsComEd's costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure. | 20292031 | Yes
|
Fair Valuevalue of Long-Term Debt
long-term debt
| Represents the difference between the carrying value and fair value of long-term debt of PHI and BGE of $569$478 million and $133$120 million, respectively, as of December 30, 201831, 2020 and $619$523 million and $139$127 million, respectively, as of December 30, 2017,31, 2019, as of the PHI and Constellation merger dates. | BGE - 2043 2036
PHI - 2045 | No |
Fair Valuevalue of PHI’s Unamortized Energy Contracts
unamortized energy contracts
| Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's, and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date. | 2036 | No |
Asset Retirement Obligationsretirement obligations | Future legally required removal costs associated with existing asset retirement obligations.AROs. | Over the life of the related assets. | Yes, once the removal activities have been performed. |
MGP Remediation Costs
remediation costs
| Environmental remediation costs for MGP sites.
sites recorded at ComEd, PECO, and BGE.
| Over the expected remediation period. See Note 22 -19 — Commitments and Contingencies for additional information. | ComEd, PECO - No |
| | | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
Renewable Energyenergy | Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts. | 2032
| No |
Electric Energyenergy and Natural Gas Costsnatural gas costs | Under (over) recoveries-recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders. | 2025 | DPL (Delaware), ACE - Yes ComEd, PECO, BGE, Pepco, DPL (Maryland) - No |
Transmission formula rate annual reconciliations
| Under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants’ FERC formula rates, which are updated annually with rates effective each June 1st.
| 20202022 | Yes |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | |
Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
Energy efficiency and demand response programs
| Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers.
| PECO - 2021 BGE - 20232025 Pepco, DPL - 20332035 | BGE, Pepco, DPL ACE - Yes PECO - Yes on capital investment recovered through this mechanism
|
Merger Integration Costsintegration costs | Integration costs to achieve distribution synergies related to the Constellation merger and PHI acquisition. Costs for Pepco (Maryland) and Pepco (District of Columbia) were $9 million each as of December 31, 2018 and $11$3 million and $9 million, respectively as of December 31, 2017.2020, which are included in Other in the table above, and $6 million and $9 million, respectively as of December 31, 2019. | BGE - 2021 Pepco - 2021 DPL- 20232026 ACE - Not currently being recovered.2022 | BGE, Pepco (Maryland), DPL - Yes
Pepco (District of Columbia), ACE - No
|
Under (Over)-Recovered Revenue Decoupling
(over)-recovered revenue decoupling
| Electric and / or gas distribution costs recoverable from or (refundable) to customers under decoupling mechanisms. | BGE and DPL - 2021 Pepco (Maryland) - $16 million - 2021 Pepco (District of Columbia) - $31 million - 2021; $46 million to be determined by the DCPSC | BGE, Pepco, and DPL - 2019 | BGE, Pepco, DPL- No |
Securitized Stranded Costs
costs
| RepresentsThe regulatory asset represents certain stranded costs associated with ACE's former electricity generation business.
The regulatory liability represents overcollection of a customer surcharge collected by ACE to fund principal and interest payments on Transition Bonds of ACE Transition Funding that securitized such costs. | Stranded costs - 2022
Overcollection - To be determined by NJBPU | Stranded costs - Yes
Overcollection - No |
| | | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
Removal Costs
costs
| For PHI,BGE, Pepco, DPL, and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, PHI, Pepco, and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes. | PHI,BGE, Pepco, DPL, and ACE - Asset is generally recovered over the life of the underliningunderlying assets.
ComEd, BGE, PHI, Pepco, and DPL - The liabilityLiability is reduced as costs are incurred.
| Yes |
DC PLUG Charge
charge
| Costs associated with DC PLUG, which is a projected six year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia. Rates for the DC Plug Initiative. See District of Columbia Regulatory Matters discussion above.PLUG initiative went into effect on February 7, 2018. | 20192021 - $30M$30 million
$12770 million to be determined based on future biennial plans filed with the DCPSC. | Portion of asset funded by Pepco-Yes
|
Deferred Storm Costsstorm costs | For Pepco, DPL, and ACE amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland and New Jersey jurisdictions. | Pepco - 20222024
DPL - 2023$2 million - 2025; $2 million not currently being recovered
ACE - 2020$5 million - 2021; $36 million not currently being recovered | Pepco, DPL - Yes
ACE - No
|
Nuclear Decommissioning
decommissioning
| Estimated future decommissioning costs for the Regulatory Agreement Units that are less than the associated NDT fund assets. See Note 15 -10 — Asset Retirement Obligations for additional informationinformation. | Not currently being refunded.
| No |
| COVID-19 | See COVID-19 section below for detail on the COVID-19 regulatory asset. | ComEd - 2024
BGE - 2025
PECO, Pepco, DPL, and ACE - Not currently being recovered. | ComEd and BGE - Yes
PECO, Pepco, DPL, and ACE - No |
| | | |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
| | | | | | | | | | | |
| Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
| Under (over) -recovered credit loss expense | For ComEd and ACE, amounts represent the difference between annual credit loss expense and revenues collected in rates through ICC and NJBPU-approved riders. The difference between net credit loss expense and revenues collected through the rider each calendar year for ComEd is recovered or refunded over a twelve-month period beginning in June of the following calendar year. ACE intends to recover/refund from June through May of each respective year, subject to approval of the NJBPU. | ComEd - 2023
ACE - To be determined by NJBPU. | No |
| Renewable portfolio standards costs | Represents an overcollection of funds from both ComEd customers and alternative retail electricity suppliers to be spent on future renewable energy procurements. Costs were $320 million as of December 31, 2019, which are included in Other in the 2019 table above. | To be determined by the IPA and ICC. | No |
COVID-19 (Exelon and the Utility Registrants). Starting in March of 2020, the Utility Registrants temporarily suspended customer disconnections for non-payment and temporarily ceased new late payment fees for all customers and restored service to customers upon request who were disconnected in the last twelve months. The duration and extent of these measures varies by jurisdiction. While these measures are no longer in place for some jurisdictions as of December 31, 2020, they are expected to continue through the first quarter of 2021 in other jurisdictions. Typically, the Utility Registrants recover credit loss expense through regulatory required programs or distribution base rate cases. ComEd and ACE have existing mechanisms for recovery of credit loss expense. For those jurisdictions without an existing regulatory required program to recover credit loss expense, the Utility Registrants are pursuing strategies to recover incremental costs being incurred as a result of COVID-19:
•In the period of April to July of 2020, the MDPSC, the DCPSC, the DPSC, and the NJBPU issued orders authorizing the creation of regulatory assets to track incremental COVID-19 related costs.
•In May of 2020, the PAPUC issued a Secretarial Letter authorizing the creation of regulatory assets to track incremental credit loss expense related to COVID-19.
The Utility Registrants have also incurred direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of their employees.
The Utility Registrants have recorded regulatory assets for the impacts of COVID-19 reflecting primarily incremental credit losses and direct costs, partially offset by a decrease in travel costs at BGE and PHI. Refer to the Regulatory assets table above for amounts as of December 31, 2020. The Utility Registrants expect to seek recovery in upcoming distribution base rate cases.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Capitalized Ratemaking Amounts Not Recognized
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | ComEd(a) | | PECO | | BGE(b) | | PHI | | Pepco(c) | | DPL(c) | | ACE |
| December 31, 2018 | $ | 65 |
| | $ | 8 |
| | $ | — |
| | $ | 49 |
| | $ | 8 |
| | $ | 5 |
| | $ | 3 |
| | $ | — |
|
| | | | | | | | | | | | | | | | |
| December 31, 2017 | $ | 69 |
| | $ | 6 |
| | $ | — |
| | $ | 53 |
| | $ | 10 |
| | $ | 6 |
| | $ | 4 |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | ComEd(a) | | PECO | | BGE(b) | | PHI | | Pepco(c) | | DPL(c) | | ACE |
| December 31, 2020 | $ | 51 | | | $ | (1) | | | $ | 0 | | | $ | 45 | | | $ | 7 | | | $ | 4 | | | $ | 3 | | | $ | 0 | |
| December 31, 2019 | $ | 63 | | | $ | 3 | | | $ | 0 | | | $ | 53 | | | $ | 7 | | | $ | 4 | | | $ | 3 | | | $ | 0 | |
__________
| |
(a) | Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets. |
| |
(b) | BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs. |
| |
(c) | Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.(a)Reflects ComEd's unrecognized equity returns/(losses) earned/(incurred) for ratemaking purposes on its electric distribution formula rate regulatory assets. (b)BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs. (c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only. |
Generation Regulatory Matters (Exelon and Generation)
Illinois Regulatory Matters
Zero Emission Standard.Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1, and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event.
Generation executed the required ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. The ZEC price was initially established at $16.50 per MWh of production, subject to annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices. Illinois utilities are required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017 to May 31, 2018, and subsequent delivery year, June 1, 2018 to May 31, 2019, the ZEC annual cost cap was set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. ForDuring the year ended December 31,first quarter of 2018, Generation recognized revenue of $373$150 million of which $150 millionrevenue related to ZECs generated from June 1, 2017 through December 31, 2017.
On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. Both lawsuits argued that the Illinois ZEC program would distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices and sought a permanent injunction preventing the implementation of the program. Exelon intervened and filed motions to dismiss in both lawsuits, which were granted by the district court. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court's dismissal of both lawsuits. The U.S. Circuit Court of Appeals for the Seventh Circuit panel denied the plaintiffs’ request for rehearing on October 9, 2018. On January 7, 2019, plaintiffs filed a petition seeking Supreme Court review of the case.
New Jersey Regulatory Matters
New Jersey Clean Energy Legislation.On May 23, 2018, the Governor of New Jersey signed newenacted legislation effective immediately, that will establishestablished a ZEC program providingthat provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $69 million and $53 million for the year ended December 31, 2020 and 2019, respectively. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU's decision to the New Jersey Superior Court. Briefing has been completed, and on December 9, 2020, oral argument took place. On October 1, 2020, PSEG and Generation filed applications seeking ZECs for the second eligibility period (June 2022 through May 2025). The NJBPU will act on the applications by the end of April 2021. Exelon and Generation cannot predict the outcome of the appeal. See Note 7 - Early Plant Retirements for additional information related to Salem.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
will be required to purchase those ZECs. Selected nuclear plants will receive annual ZEC payments for each energy year (12-month period from June 1 through May 31) within 90 days after the completion of such energy year. The quantity of ZECs issued will be determined based on the greater of 40% of the total number of MWh of electricity distributed by the public electric distribution utilities in New Jersey in the prior year, or the total number of MWh of electricity generated in the prior year by the selected nuclear power plants. The ZEC price is approximately $10 per MWh during the first 3-year eligibility period. For eligibility periods following the first 3-year eligibility period, the NJBPU has discretion to reduce the ZEC price. On November 19, 2018, the NJBPU issued an order providing for the method and application process for determining the eligibility of nuclear power plants, a draft method and process for ranking and selecting eligible nuclear power plants, and the establishment of a mechanism for each regulated utility to purchase ZECs from selected nuclear power plants. On December 19, 2018, PSEG filed complete applications seeking NJBPU approval for Salem 1 and Salem 2, of which Generation owns a 42.59% ownership interest, to participate in the ZEC program. On the same day, Generation filed certain Supplemental Information with the NJBPU providing proprietary information that was requested in the application but which could not be shared with PSEG. The NJBPU must complete its processes for determining eligibility for, and participation in, the ZEC program by April 18, 2019. See Note 8 - Early Plant Retirements for additional information on New Jersey’s ZEC program potential impacts to PSEG’s Salem nuclear plant.3 — Regulatory Matters
New York Regulatory Matters
New York Clean Energy Standard.On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which includedis a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that met specificmeet the criteria demonstrating public necessity as determined by the NYPSC to be Generation's FitzPatrick, Ginna, and Nine Mile Point nuclear facilities. The New York State Energy Research and Development Authority (NYSERDA) centrally procures the ZECs through a 12-year contract extending from April 1, 2017 through March 31, 2029, administered in six two-year tranches. ZEC payments are made based upon the number of MWh produced by each facility, subject to specified caps and minimum performance requirements. The ZEC price for the first tranche was set at $17.48 per MWh of production and is administratively determined using a formula based on the social cost of carbon as determined in 2016 by the federal government, subject to pricing adjustments designed to lower the ZEC price based on increases in underlying energy and capacity prices. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) is required to purchase an amount of ZECs from NYSERDA equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers is incorporated into the commodity charges on customer bills.
Generation is currently recognizing revenue for the sale of New York ZECs in the month they are generated and for the years ended December 31, 2018 and 2017, Generation has recognized revenue of $438 million and $311 million, respectively.
On October 19, 2016, a coalition of fossil-generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically, that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors. On December 9, 2016, several parties filed motions to intervene in the case and to dismiss the lawsuit. On July 25, 2017, the court granted the motions to dismiss. On September 27, 2018, the U.S. Court of Appeals for the Second Circuit affirmed the lower court's dismissal of the complaint against the ZEC program. On January 7, 2019, the fossil-generation companies filed a petition seeking Supreme Court review of the case.
In addition, on November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. Subsequently, Generation, CENG and the NYPSC filed motions to dismiss the state court action, which were later opposed by the plaintiffs. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. Generation, CENG andOn October 8, 2019, the state's answers and briefs were filed on March 30, 2018. On December 17, 2018, plaintiffscourt dismissed all remaining claims. The petitioners filed a replynotice of appeal on November 4, 2019 and originally had until May 4, 2020 to file their brief. Due to COVID-19 related restrictions, the court extended the deadline to July 29, 2020. Petitioners did not file a brief introducing new arguments and new evidence. The State of New York filedby the deadline, so the case is deemed dismissed. Petitioners are permitted up to one year from July 29, 2020 to file a motion to strike on December 28, 2018. On January 4, 2019, Generation and CENG filed a motion to strikevacate the new arguments and new evidence. After briefing is completed,dismissal if they can show good cause for the court will decide whether or not to set the case for hearing.delay.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 8 -7 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point,Point.
New England Regulatory Matters
Mystic Units 8 & 9 and Everett Marine Terminal Cost of Service Agreement (Exelon and Generation). On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 & 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service compensation, reflecting a number of adjustments to the annual fixed revenue requirement, and allowing for recovery of a substantial portion of the costs associated with the adjacent Everett Marine Terminal acquired by Generation in October 2018. Those adjustments were reflected in a compliance filing made on March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. On January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings in the order.
On July 17, 2020, FERC issued three orders, which together affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of the Everett Marine Terminal. FERC directed a downward adjustment to the rate base for Mystic Units 8 and 9, the effect of which will be partially offset by elimination of a crediting mechanism for third party gas sales during the term of the cost of service agreement. A compliance filing was submitted on September 15, 2020 and is pending. Several parties filed protests to the compliance filing on the issue of how gross plant in-service was calculated and Generation filed an answer to the protests on October 21, 2020. On July 28, 2020, FERC ordered additional briefings in the ROE proceeding. On December 21, 2020, FERC issued an order on rehearing of the three July 17, 2020 orders, clarifying several cost of service provisions.
On August 25, 2020, a group of New England generators filed a complaint against Generation seeking to extend the scope of the claw back provision in the cost-of-service agreement, whereby Generation would refund certain amounts recovered during the term of the cost of service if it returns to market afterwards. On September 14, 2020, Generation filed an answer to the complaint arguing that the complaint is procedurally improper and a collateral attack on existing FERC orders, and pointing out that the ISO-NE tariff contains protections against the New England generators' concerns that they failed to mention. On September 28, 2020, New England generators filed an answer to Generation’s answer. Generation cannot predict the outcome of this proceeding.
On June 10, 2020, Generation filed a complaint with FERC against ISO-NE on the grounds that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic for transmission security for the 2024 to 2025 Capacity Commitment Period (FCA 15) and that the modifications that ISO-NE made to its unfiled planning procedures to avoid retaining Mystic should have been filed with FERC for approval. On July 27, 2020, ISO-NE issued a memo to NEPOOL announcing its determination pursuant to its unfiled planning procedures that Mystic Units 8 and 9 are not needed for FCA 15 for transmission security. It had previously determined Mystic Units 8 and 9 are not needed for fuel security. On August 17, 2020, FERC issued an order denying the complaint. On September 16,
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
2020, Generation filed a request for rehearing with FERC. On October 19, 2020, FERC denied rehearing by operation of law and on December 18, 2020, Generation appealed to the U.S. Court of Appeals for the D.C. Circuit. The timing and the outcome of this proceeding is uncertain.
See Note 7 — Early Plant Retirements and Note 5 - Mergers, Acquisitions and Dispositions12 — Asset Impairments for additional information on Generation's acquisition of FitzPatrick.
Ginna Nuclear Power Plant Reliability Support Services Agreement. In November 2014, in response to a petition filed by Ginna Nuclear Power Plant (Ginna) regarding the possible retirement of Ginna, the NYPSC directed Ginna and Rochester Gas & Electric Company (RG&E) to negotiate a RSSA to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time.
On April 8, 2016, FERC accepted Ginna’s compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA with a term expiring on March 31, 2017. In April 2016, Generation began recognizing revenue based on the final approved pricing contained in the RSSA and also recognized a one-time revenue adjustment of $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date through March 31, 2016. A 49.99% portion of the one-time adjustment was removed from Generation’s results of operations as a result of the noncontrolling interests in CENG.
The RSSA required Ginna to continue operating through the RSSA term. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the New York CES. Subject to prevailing over any administrative or legal challenges, it is expected the New York CES will allow Ginna to continue to operate through the end of its current operating license in 2029. See Note 8 - Early Plant Retirements for additional information regarding the impacts of aGeneration’s August 2020 decision to early retire a nuclear plant.Mystic Units 8 & 9 upon expiration of the cost of service agreement.
Federal Regulatory Matters
PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a MOPR. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a state government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the MOPR in NYISO applies only to certain resources in downstate New York.
For Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation, an expanded MOPR would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions.
On December 19, 2019, FERC required PJM to broadly apply the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage, and all resources owned by vertically-integrated utilities. This greatly expands the breadth and scope of PJM’s MOPR, which is effective as of PJM’s next capacity auction. While FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources.
FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism (under which an entire utility zone would be removed from PJM’s capacity auction along with sufficient resources to support the load in such zone). In response to FERC’s order, PJM submitted a compliance filing on March 18, 2020 wherein PJM proposed tariff language interpreting and implementing FERC's directives, and proposed a schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing.
On April 16, 2020, FERC issued an order largely denying most requests for rehearing of FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing which PJM submitted on June 1, 2020.
On October 15, 2020, FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting PJM’s two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, FERC also accepted PJM’s proposal to condense the schedule of activities leading up to the next capacity auction. In November 2020, PJM announced that it will conduct its next capacity auction beginning on May 19, 2021 and ending on May 25, 2021 and will post the results on June 2, 2021.
Because neither Illinois nor New Jersey have implemented an FRR program in their PJM zones, the MOPR will apply in that next capacity auction to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES, or the New Jersey ZEC program, as applicable, increasing the risk that those units may not clear the capacity market.
Exelon is currently working with PJM and other stakeholders to pursue the FRR option as an alternative to the PJM capacity auction. If Illinois implements the FRR option, Generation’s Illinois nuclear plants could be removed from PJM’s capacity auction and instead supply capacity, and be compensated under the FRR program, which has the potential to mitigate the current economic distress being experienced by Generation's nuclear plants in Illinois, as discussed in Note 7 — Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative and regulatory changes. Whether legislation is needed in New Jersey would depend on how the state chooses to structure an FRR program. Exelon cannot predict whether or when such legislative and regulatory changes can be implemented.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
On February 20, 2020, FERC issued an order rejecting requests to expand NYISO’s version of the MOPR (referred to as buyer-side mitigation rules) beyond its current limited applicability to certain resources in downstate. However, on October 14, 2020, two natural gas-fired generators in New York filed a complaint at FERC seeking to expand the MOPR in NYISO to apply to all resources, new and existing, across the entire NYISO market. Exelon is strenuously opposing expansion of FERC’s MOPR policies in the NYISO market. While it is too early in the proceeding to predict its outcome and there are significant differences between the NYISO and PJM markets that would justify a different result, if FERC follows its MOPR precedent in PJM and applies the MOPR in NYISO broadly as requested in the complaint, Generation’s facilities in NYISO that are receiving ZEC compensation may be at increased risk of not clearing the capacity auction.
If Generation’s state-supported nuclear plants in PJM or NYISO are subjected to the MOPR or equivalent without compensation under an FRR or similar program, it could have a material adverse impact on Exelon's and Generation's financial statements, which Exelon and Generation cannot reasonably estimate at this time.
Operating License Renewals
Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a 46-yearnew license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) with Maryland Department of the Environment (MDE)from MDE for Conowingo, Generation continues to workhas been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.
On April 21, 2016, Generation and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a Settlement Agreementsettlement agreement (DOI Settlement) resolving all fish passage issues between the parties. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the life of the new license, including both capital and operating costs. The actual timing and amount of these costs are not currently fixed and may vary significantly from year to year throughout the life of the new license.
On April 27, 2018, the MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contains numerous conditions, including those relating to reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage, which could have a material, unfavorable impact on Exelon’s and Generation’s financial statements through an increase in capital expenditures and operating costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the conditions are unfair and onerous violatingand in violation of MDE regulations and state, federal, and constitutional law. Generation also requested that FERC defer action onthe issuance of the federal license while these significant state and federal law issues are pending. On July 9, 2018,February 28, 2019, Generation filed a Petition for Declaratory Order with FERC requesting that FERC issue an order declaring that MDE waived its right to issue a 401 Certification for Conowingo because it failed to timely act on Conowingo’s 401 Certification application and requesting that FERC decline to include the conditions required by MDE in April 2018.
On October 29, 2019, Generation and MDE filed with FERC a motionJoint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to dismiss Generation's complaintthe 401 Certification. Pursuant to the Offer of Settlement, the parties submitted Proposed License Articles to FERC to be incorporated by FERC into the new license in state court, which was grantedaccordance with FERC’s discretionary authority under the Federal Power Act. Among the Proposed License Articles are modifications to river flows to improve aquatic habitat, eel passage improvements, and initiatives to support rare, threatened and endangered wildlife. If FERC approves the Offer of Settlement and incorporates the Proposed License Articles into the new license without prejudice on October 9, 2018. The court found MDE'smodification, then MDE would waive its rights to issue a 401 Certification was notand Generation would agree, pursuant to a "final decision" of Exelon's rightsseparate agreement with MDE (MDE Settlement), to implement additional environmental protection, mitigation, and because Exelon's motion for reconsideration remains pending, as does its administrative appealenhancement measures over the anticipated 50-year term of the 401 Certification, there was no final administrative decision fornew license. These measures address mussel restoration and other ecological and water quality matters, among other commitments. Exelon’s commitments under the courtvarious provisions of the Offer of Settlement and MDE Settlement are not effective unless and until FERC approves the Offer of Settlement, and issues the new license with the Proposed License Articles.
The financial impact of the DOI and MDE Settlements and other anticipated license commitments are estimated to review at this time. On November 5, 2018, Exelon appealedbe $11 million to $14 million per year, on average, recognized over the Maryland Circuit Court's dismissalnew license term, including capital and operating costs. The actual timing and amount of Exelon's state complaint. Exelon continuesthe majority of these costs are not currently fixed and will vary from year to challengeyear throughout the 401 Certification throughlife of the administrative process and in federal court. Exelon andnew license. Generation cannot currently predict when FERC will issue the final outcome or its financial impact, if any, on Exelon or Generation.
new license. As of December 31, 2018, $372020, $45 million of direct costs associated with Conowingo licensing efforts have been capitalized. Generation's current depreciation provision for Conowingo assumes renewal of the FERC license.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Peach Bottom Units 2 and 3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3. Generation anticipates3, which was approved on March 6, 2020. Peach Bottom Units 2 and 3 are now licensed to operate through 2053 and 2054, respectively. See Note 8 – Property, Plant, and Equipment for additional information regarding the second license renewal processestimated useful life and depreciation provisions for Peach Bottom.
4. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to takedepict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue and no variable consideration for regulated electric and gas tariff sales and regulated transmission services unless noted below.
Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, the Registrants generally recognize revenue in the amount for which they have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
approximately 2 years | | | | | | | | | | | | | | |
| Revenue Source | Description | Performance Obligation | Timing of Revenue Recognition | Payment Terms |
| Competitive Power Sales (Exelon and Generation) | Sales of power and other energy-related commodities to wholesale and retail customers across multiple geographic regions through its customer-facing business, Constellation. | Various including the delivery of power (generally delivered over time) and other energy-related commodities such as capacity (generally delivered over time), ZECs, RECs or other ancillary services (generally delivered at a point in time). | Concurrently as power is generated for bundled power sale contracts. (a) | Within the month following delivery to the customer. |
| Competitive Natural Gas Sales (Exelon and Generation) | Sales of natural gas on a full requirement basis or for an agreed upon volume to commercial and residential customers. | Delivery of natural gas to the customer. | Over time as the natural gas is delivered and consumed by the customer. | Within the month following delivery to the customer. |
| Other Competitive Products and Services (Exelon and Generation) | Sales of other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers. | Construction and/or installation of the asset for the customer. | Revenues and associated costs are recognized throughout the contract term using an input method to measure progress towards completion.(b) | Within 30 or 45 days from the invoice date. |
| Regulated Electric and Gas Tariff Sales (Exelon and the Utility Registrants) | Sales of electricity and electricity distribution services (the Utility Registrants) and natural gas and gas distribution services (PECO, BGE, and DPL) to residential, commercial, industrial, and governmental customers through regulated tariff rates approved by state regulatory commissions. | Delivery of electricity and/or natural gas. | Over time (each day) as the electricity and/or natural gas is delivered to customers. Tariff sales are generally considered daily contracts as customers can discontinue service at any time. (c) | Within the month following delivery of the electricity or natural gas to the customer. |
| Regulated Transmission Services (Exelon and the Utility Registrants) | The Utility Registrants provide open access to their transmission facilities to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants pursuant to filed tariffs at cost-based rates approved by FERC. | Various including (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid. | Over time utilizing output methods to measure progress towards completion. (d) | Paid weekly by PJM. |
__________
(a)Certain contracts may contain limits on the application submission until completiontotal amount of revenue Exelon and Generation are able to collect over the entire term of the NRC’s review process. Peach Bottom Units 2contract. In such cases, Exelon and 3 are currently licensedGeneration estimate the total consideration expected to operate through 2033be received over the term of the contract net of the constraint and 2034, respectively.
PJM Transmission Rate Design. Refer to Other Federal Regulatory Matters above for additional information.
5. Mergers, Acquisitions and Dispositions (Exelon, Generation and PHI)
Acquisition of FirstEnergy Solutions Load Business (Exelon and Generation)
On July 9, 2018, Generation entered into an Asset Purchase Agreement (the Purchase Agreement) with FirstEnergy Solutions Corporation (FirstEnergy). Pursuantallocate the expected consideration to the Purchase Agreement, FirstEnergy agreed to assign allperformance obligations
Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)
On March 31, 2017, Generation acquired the 842 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York from Entergy Nuclear FitzPatrick LLC (Entergy) for a total purchase price of $289 million, which consisted of a cash purchase price of $110 million and a net cost reimbursement to and on behalf of Entergy of $179 million. As part of the acquisition agreements, Generation provided nuclear fuel and reimbursed Entergy for incremental costs to prepare for and conduct a plant refueling outage; and Generation reimbursed Entergy for incremental costs to operate and maintain the plant for the period after the refueling outage through the acquisition closing date. These reimbursements covered costs that Entergy otherwise would have avoided had it shutdown the plant as originally intended in January 2017. The amounts reimbursed by Generation were offset by FitzPatrick's electricity and capacity sales revenues for this same post-outage period. As part of the transaction, Generation received the FitzPatrick NDT fund assets and assumed the obligation to decommission FitzPatrick. The NRC license for FitzPatrick expires in 2034.
The fair values of FitzPatrick’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices.
An after-tax bargain purchase gain of $233 million was included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income which primarily reflects differences in strategies between Generation and Entergy for the intended use and ultimate decommissioning of the plant. See Note 15 — Asset Retirement Obligations and Note 16 — Retirement Benefits for additional information regarding the FitzPatrick decommissioning ARO and pension and OPEB updates.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.
(b)The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months.
(c)Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.
(d)Passage of time is used for NITS and access to the wholesale grid and MWHs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services.
Generation incurs incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and were immaterial as of December 31, 2020 and 2019. The Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.
Contract Balances (All Registrants)
Contract Assets
Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current assets and Customer accounts receivable, net, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets.
The following table summarizes the final acquisition-date fair valueprovides a rollforward of the consideration transferred and thecontract assets and liabilities assumed for the FitzPatrick acquisition by Generation:
|
| | | | |
| Cash paid for purchase price | | $ | 110 |
|
| Cash paid for net cost reimbursement | | 125 |
|
| Nuclear fuel transfer | | 54 |
|
| Total consideration transferred | | $ | 289 |
|
| | | |
| Identifiable assets acquired and liabilities assumed | | |
| Current assets | | $ | 60 |
|
| Property, plant and equipment | | 298 |
|
| Nuclear decommissioning trust funds | | 807 |
|
Other assets(a) | | 114 |
|
| Total assets | | $ | 1,279 |
|
| | | |
| Current liabilities | | $ | 6 |
|
| Nuclear decommissioning ARO | | 444 |
|
| Pension and OPEB obligations | | 33 |
|
| Deferred income taxes | | 149 |
|
| Spent nuclear fuel obligation | | 110 |
|
| Other liabilities | | 15 |
|
| Total liabilities | | $ | 757 |
|
| Total net identifiable assets, at fair value | | $ | 522 |
|
| | | |
| Bargain purchase gain (after-tax) | | $ | 233 |
|
_________
| |
(a) | Includes a $110 million asset associated with a contractual right to reimbursement from the New York Power Authority (NYPA), a prior owner of FitzPatrick, associated with the DOE one-time fee obligation. See Note 22-Commitments and Contingencies for additional information regarding SNF obligations to the DOE. |
Exelon and Generation incurred $57 million of merger and integration related costs to FitzPatrick for the year ended December 31, 2017 which are included within Operating and maintenance expensereflected in Exelon's and Generation's Consolidated Balance Sheets. The Utility Registrants do not have any contract assets.
| | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Balance as of December 31, 2018 | | $ | 187 | | | $ | 187 | | | | | |
| Amounts reclassified to receivables | | (143) | | | (143) | | | | | |
| Revenues recognized | | 130 | | | 130 | | | | | |
| Balance at December 31, 2019 | | 174 | | | 174 | | | | | |
| Amounts reclassified to receivables | | (86) | | | (86) | | | | | |
| Revenues recognized | | 68 | | | 68 | | | | | |
Contract assets reclassified as held for sale(a) | | (12) | | | (12) | | | | | |
| Balance at December 31, 2020 | | $ | 144 | | | $ | 144 | | | | | |
__________
(a)Represents contract assets related to Generation's solar business, which were classified as held for sale as a result of the sale agreement. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.
Contract Liabilities
The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities within Other current liabilities and Other noncurrent liabilities within the Registrants' Consolidated Balance Sheets.
For Generation, these contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases, and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. The Generation contract liability related to the Illinois ZEC program includes certain amounts with ComEd that are eliminated in consolidation in Exelon’s Consolidated Statements of Operations and Comprehensive Income. Exelon and Generation did not incur any merger and integration costs related to FitzPatrick for the year ended December 31, 2018.
Acquisition of ConEdison Solutions (Exelon and Generation)Consolidated Balance Sheets.
On SeptemberJuly 1, 2016, Generation acquired the competitive retail electricity2020, Pepco, DPL, and natural gas businessACE each entered into a collaborative arrangement with an unrelated owner and manager of Consolidated Edison Solutions, Inc. (ConEdison Solutions),communication infrastructure (the Buyer). Under this arrangement, Pepco, DPL, and ACE sold a subsidiary60% undivided interest in their respective portfolios of Consolidated Edison, Inc. for a purchase pricetransmission tower attachment agreements with
The purchase price of $257 million equaled the estimated fair value of the net assets acquired and the liabilities assumed and, therefore, no goodwill or bargain purchase was recorded as of the acquisition date.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
Merger with Pepco Holdings, Inc. (Exelon)
Description of Transaction
On March 23, 2016, Exelon completedtelecommunications companies to the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub) and Pepco Holdings, Inc. (PHI), for a total purchase price consideration of approximately $7.1 billion. As a resultBuyer, in addition to transitioning management of the merger, Merger Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and Exelon Energy Delivery Company, LLC (EEDC), a wholly owned subsidiary of Exelon which also owns Exelon's interests in ComEd, PECO and BGE (through a special purpose subsidiary in the case of BGE). Following the completionday-to-day operations of the PHI Merger, Exelonjointly-owned agreements to the Buyer for 35 years, while retaining the safe and PHI completed a seriesreliable operation of internal corporate organization restructuring transactions resulting inits utility assets. In return, Pepco, DPL, and ACE will provide the transferBuyer limited access on the portion of PHI’s unregulated business interests to Exelon and Generationthe towers where the equipment resides for the purposes of managing the agreements for the benefit of Pepco, DPL, ACE, and the transferBuyer. In addition, for an initial period of three years and two, two-year extensions that are subject to certain conditions, the Buyer has the exclusive right to enter into new agreements with telecommunications companies and to receive a 30% undivided interest in those new agreements. PHI, Pepco, DPL, and ACE to a special purpose subsidiaryreceived cash and recorded contract liabilities as of EEDC.
Regulatory Matters
Approval of the merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments including where applicable: customer rate credits, funding for energy efficiency and delivery system modernization programs, a green sustainability fund, workforce development initiatives, charitable contributions, renewable generation and other required commitments. In addition, the orders approving the merger in Delaware, New Jersey and Maryland include a “most favored nation” provision which, generally, requires allocation of merger benefits proportionally across all the jurisdictions.
Total nominal cost of commitments was $513 million excluding renewable generation commitments (approximately $444 million on a net present value basis amount, excluding renewable generation commitments and charitable contributions).
During the fourth quarter of 2018, Exelon finalized the application of $5 million funding for residential and non-residential customersJuly 1, 2020 as shown in the DPL Maryland service territory. This resulted in an adjustmenttable below. The revenue attributable to merger commitment costs recorded at Exelon Corporate and DPL. Exelon Corporate recorded a decrease of $5 million and DPL recorded an increase of $5 million in Operating and maintenance expense.this arrangement will be recognized as operating revenue over the 35 years under the collaborative arrangement.
The following amounts represent total commitment coststable provides a rollforward of the contract liabilities reflected in Exelon's, Generation's, PHI's, Pepco's, DPL's, and ACE'S Consolidated Balance Sheets. As of December 31, 2020, 2019, and 2018, ComEd's, PECO's, and BGE's contract liabilities were immaterial.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | PHI | | Pepco | | DPL | | ACE |
| Balance as of December 31, 2017 | $ | 35 | | | $ | 35 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Consideration received or due | 179 | | | 465 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Revenues recognized | (187) | | | (458) | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance as of December 31, 2018 | 27 | | | 42 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Consideration received or due | 94 | | | 287 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Revenues recognized | (88) | | | (258) | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance at December 31, 2019 | 33 | | | 71 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Consideration received or due | 219 | | | 282 | | | 122 | | | 98 | | | 12 | | | 12 | |
| Revenues recognized | (98) | | | (266) | | | (4) | | | (4) | | | 0 | | | 0 | |
Contracts liabilities reclassified as held for sale(a) | (3) | | | (3) | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance at December 31, 2020 | $ | 151 | | | $ | 84 | | | $ | 118 | | | $ | 94 | | | $ | 12 | | | $ | 12 | |
__________
(a)Represents contract liabilities related to Generation's solar business, which were classified as held for Exelon, PHI, Pepco, DPLsale as a result of the sale agreement. See Note 2 — Mergers, Acquisitions, and ACE that have been recorded since the merger date:Dispositions for additional information.
|
| | | | | | | | | | | | | | | | | | | | | |
| | Expected Payment Period | | | | Successor | | | | | | |
| Description | | Exelon | | PHI | | Pepco | | DPL | | ACE |
| Rate credits | 2016 - 2021 | | $ | 259 |
| | $ | 264 |
| | $ | 91 |
| | $ | 72 |
| | $ | 101 |
|
| Energy efficiency | 2016 - 2021 | | 117 |
| | — |
| | — |
| | — |
| | — |
|
| Charitable contributions | 2016 - 2026 | | 50 |
| | 50 |
| | 28 |
| | 12 |
| | 10 |
|
| Delivery system modernization | Q2 2017 | | 22 |
| | — |
| | — |
| | — |
| | — |
|
| Green sustainability fund | Q2 2017 | | 14 |
| | — |
| | — |
| | — |
| | — |
|
| Workforce development | 2016 - 2020 | | 17 |
| | — |
| | — |
| | — |
| | — |
|
| Other | | | 29 |
| | 6 |
| | 1 |
| | 5 |
| | — |
|
| Total commitments | | | $ | 508 |
| | $ | 320 |
| | $ | 120 |
| | $ | 89 |
| | $ | 111 |
|
| Remaining commitments as of December 31, 2018 | | | $ | 128 |
| | $ | 92 |
| | $ | 73 |
| | $ | 12 |
| | $ | 7 |
|
Pursuant to the orders approving the merger, Exelon made $73 million, $46 million and $49 million of equity contributions to Pepco, DPL and ACE, respectively,The following table reflects revenues recognized in the second quarter of 2016years ended December 31, 2020, 2019 and 2018, which were included in contract liabilities at December 31, 2019, 2018, and 2017, respectively:
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 |
| Exelon | $ | 27 | | | $ | 18 | | | $ | 11 | |
| Generation | 64 | | | 32 | | | 11 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Transaction Price Allocated to fundRemaining Performance Obligations (All Registrants)
The following table shows the after-tax amounts of the customer bill credit and the customer base rate credit commitments.
In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia and Delaware, at an estimated cost of approximately $127 million, which will generate future earnings at Exelon and Generation. Investment costs, which arerevenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2020. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
This disclosure excludes Generation's power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
primarily capital | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2022 | | 2023 | | 2024 | | 2025 and thereafter | | Total |
| Exelon | $ | 262 | | | $ | 93 | | | $ | 54 | | | $ | 40 | | | $ | 330 | | | $ | 779 | |
| Generation | 352 | | | 124 | | | 55 | | | 34 | | | 243 | | | 808 | |
| PHI | 9 | | | 8 | | | 8 | | | 6 | | | 87 | | | 118 | |
| Pepco | 7 | | | 6 | | | 6 | | | 5 | | | 70 | | | 94 | |
| DPL | 1 | | | 1 | | | 1 | | | 0 | | | 9 | | | 12 | |
| ACE | 1 | | | 1 | | | 1 | | | 1 | | | 8 | | | 12 | |
Revenue Disaggregation (All Registrants)
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of the Registrant's revenue disaggregation.
5. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODM in nature, will be recognized as incurreddeciding how to evaluate performance and recorded on Exelon's and Generation's financial statements. Asallocate resources at each of December 31, 2018, 27 MWs were developed and Exelon and Generation have incurred costs of $83 million. the Registrants.
Exelon has also committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two11 reportable segments, which include Generation's 5 reportable segments consisting of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017Mid-Atlantic, Midwest, New York, ERCOT, and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018all other power regions referred to collectively as “Other Power Regions” and resulted in a proposed REC purchase agreement that is pending reviewComEd, PECO, BGE, and approval with the DPSC. The thirdPHI's 3 reportable segments consisting of Pepco, DPL, and final 40 MW wind REC tranche will be conducted in 2022.
Pursuant to the various jurisdictions' merger approval conditions, over specified periodsACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL, and ACE based on net income.
The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are not permittedalso aligned to reduce employment levels due to involuntary attrition associated with the merger integration process and have made other commitments regarding hiring and relocationthese same geographic regions. Descriptions of positions.each of Generation’s 5 reportable segments are as follows:
In July 2015, the OPC, Public Citizen, Inc., the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed motions to stay the MDPSC order approving the merger. The Circuit Court judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, CCAN and Public Citizen, Inc. On January 19, 2016, the OPC filed a notice of appeal to the Maryland Court of Special Appeals, and on January 21, the Sierra Club and CCAN filed notices of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court's judgment that the MDPSC did not err in approving the merger. The OPC and Sierra Club filed petitions seeking further review•Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Court of Appeals, which is the highest court in Maryland. On August 29, 2018, the Maryland Court of Appeals affirmed the MDPSC's May 2015 Order approving the merger of Exelon and PHI.
Between March 25, 2016 and April 22, 2016, various parties filed motions with the DCPSC to reconsider its March 23, 2016 order approving the merger. On June 17, 2016, the DCPSC denied all motions. In August 2016, the District Legal Entity of Columbia Office of People’s Counsel,Virginia, West Virginia, Delaware, the District of Columbia, Government, and Public Citizen jointly with DC Sun each filed petitions for judicial reviewparts of Pennsylvania and North Carolina.
•Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.
•New York represents operations within NYISO.
•ERCOT represents operations within Electric Reliability Council of Texas.
•Other Power Regions:
•New England represents operations within ISO-NE.
•South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the DCPSC’s March 23, 2016 order withSERC not included within MISO or PJM.
•West represents operations in the DistrictWECC, which includes CAISO.
•Canada represents operations across the entire country of Columbia CourtCanada and includes AESO, OIESO, and the Canadian portion of Appeals. On July 20, 2017, the Court issued an opinion rejecting all of appellants’ arguments and affirming the Commission’s decision approving the merger.
Accounting for the Merger TransactionMISO.
The total purchase price considerationCODMs for the PHI merger was approximately $7.1 billion. The excess of the purchase price over the estimated fair value of the assets acquired and the liabilities assumed totaled $4 billion, which was recognized as goodwill by PHI and Exelon at the merger date, reflecting the value associated with enhancing Exelon's regulated utility portfolio of businesses, including the ability to leverage experience and best practices across the utilities and the opportunities for synergies. None of this goodwill is expected to be tax deductible. For purposes of future required impairment assessments, the goodwill has been assigned to PHI's reportable units Pepco, DPL and ACE. See Note 10 - Intangible Assets for additional information.
Immediately following closing of the merger, $235 million of net assets associated with PHI's unregulated business interests were distributed by PHI to Exelon. Exelon contributed $163 million of such net assets to Generation.
Rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on invested capital, or rate base, generally measured at historical cost. Historical cost information therefore is the most relevant presentation for the financial statements of PHI’s rate regulated utility subsidiary registrants, Pepco, DPL and ACE. As such, Exelon and PHI didGeneration evaluate the performance of Generation’s electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measurement of operational performance. RNF is not push-down the applicationa presentation defined under GAAP and may not be comparable to other companies’
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The current impactresults of PHI, includingGeneration's other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its unregulated businesses,amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in Exelon's Consolidated Statementsmaking decisions regarding allocating resources to or assessing the performance of Operationsthese reportable segments.
An analysis and Comprehensive Income includes Operating revenuesreconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the years ended December 31, 2020, 2019, and Net Income (Loss)2018 is as follows:
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Operating Revenues | 4,670 |
| | 4,829 |
| | 3,785 |
|
| Net Income (Loss) | 453 |
| | 364 |
| | (66 | ) |
For the periods ended December 31, 2018, 2017 and 2016, the Registrants have recognized costs to achieve the PHI merger as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
Operating revenues(b): | | | | | | | | | | | | | | | |
| 2020 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 15,060 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | (1,196) | | | $ | 13,864 | |
| Competitive businesses natural gas revenues | 2,003 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (3) | | | 2,000 | |
| Competitive businesses other revenues | 540 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (4) | | | 536 | |
| Rate-regulated electric revenues | 0 | | | 5,904 | | | 2,543 | | | 2,336 | | | 4,485 | | | 0 | | | (61) | | | 15,207 | |
| Rate-regulated natural gas revenues | 0 | | | 0 | | | 515 | | | 762 | | | 162 | | | 0 | | | (7) | | | 1,432 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 0 | | | 16 | | | 2,035 | | | (2,051) | | | 0 | |
| Total operating revenues | $ | 17,603 | | | $ | 5,904 | | | $ | 3,058 | | | $ | 3,098 | | | $ | 4,663 | | | $ | 2,035 | | | $ | (3,322) | | | $ | 33,039 | |
| 2019 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 16,285 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | (1,165) | | | $ | 15,120 | |
| Competitive businesses natural gas revenues | 2,148 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (1) | | | 2,147 | |
| Competitive businesses other revenues | 491 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (4) | | | 487 | |
| Rate-regulated electric revenues | 0 | | | 5,747 | | | 2,490 | | | 2,379 | | | 4,626 | | | 0 | | | (47) | | | 15,195 | |
| Rate-regulated natural gas revenues | 0 | | | 0 | | | 610 | | | 727 | | | 167 | | | 0 | | | (15) | | | 1,489 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 0 | | | 13 | | | 1,921 | | | (1,934) | | | 0 | |
| Total operating revenues | $ | 18,924 | | | $ | 5,747 | | | $ | 3,100 | | | $ | 3,106 | | | $ | 4,806 | | | $ | 1,921 | | | $ | (3,166) | | | $ | 34,438 | |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
Acquisition, Integration and Financing Costs(a) | 2018 | | 2017 | | 2016 |
| Exelon | $ | 7 |
| | $ | 16 |
| | $ | 143 |
|
| Generation | 5 |
| | 22 |
| | 37 |
|
ComEd(b) | — |
| | 1 |
| | (6 | ) |
| PECO | 1 |
| | 4 |
| | 5 |
|
BGE(b) | 1 |
| | 4 |
| | (1 | ) |
Pepco(b) | — |
| | (6 | ) | | 28 |
|
DPL(b) | — |
| | (7 | ) | | 20 |
|
ACE(b) | — |
| | (6 | ) | | 19 |
|
|
| | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the Year Ended December 31, | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to
March 23, 2016 |
Acquisition, Integration and Financing Costs(a) | 2018 | | 2017 | | | |
PHI(b) | $ | — |
| | $ | (18 | ) | | $ | 69 |
| | | $ | 29 |
|
______________
| |
(a) | The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above. |
| |
(b) | For the year ended December 31, 2017, includes deferrals of previously incurred integration costs as regulatory assets of $24 million, $8 million, $8 million, and $8 million at PHI, Pepco, DPL and ACE, respectively. For the year ended December 31, 2016, includes deferrals of previously incurred integration costs as regulatory assets of $8 million, $6 million, $11 million and $4 million at ComEd, BGE, Pepco and DPL, respectively. For the Successor period March 24, 2016 to December 31, 2016, includes deferrals of previously incurred integration costs as regulatory assets of $16 million at PHI. See Note 4 - Regulatory Matters for additional information. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
Pro-forma Impact of the Merger
The following unaudited pro-forma financial information reflects the consolidated results of operations of Exelon as if the PHI merger had taken place on January 1, 2015. The unaudited pro forma information was calculated after applying Exelon’s accounting policies and adjusting PHI’s results to reflect purchase accounting adjustments.
The unaudited pro-forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or future consolidated results of operations of the combined company. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
| 2018 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 17,411 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | (1,256) | | | $ | 16,155 | |
| Competitive businesses natural gas revenues | 2,718 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (8) | | | 2,710 | |
| Competitive businesses other revenues | 308 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (5) | | | 303 | |
| Rate-regulated electric revenues | 0 | | | 5,882 | | | 2,470 | | | 2,428 | | | 4,602 | | | 0 | | | (45) | | | 15,337 | |
| Rate-regulated natural gas revenues | 0 | | | 0 | | | 568 | | | 741 | | | 181 | | | 0 | | | (20) | | | 1,470 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 0 | | | 15 | | | 1,948 | | | (1,960) | | | 3 | |
| Total operating revenues | $ | 20,437 | | | $ | 5,882 | | | $ | 3,038 | | | $ | 3,169 | | | $ | 4,798 | | | $ | 1,948 | | | $ | (3,294) | | | $ | 35,978 | |
| | | | | | | | | | | | | | | |
Intersegment revenues(c): | | | | | | | | | | | | | | | |
| 2020 | $ | 1,211 | | | $ | 37 | | | $ | 9 | | | $ | 20 | | | $ | 17 | | | $ | 2,024 | | | $ | (3,314) | | | $ | 4 | |
| 2019 | 1,172 | | | 30 | | | 6 | | | 26 | | | 14 | | | 1,913 | | | (3,159) | | | 2 | |
| 2018 | 1,269 | | | 27 | | | 8 | | | 29 | | | 15 | | | 1,942 | | | (3,289) | | | 1 | |
| Depreciation and amortization: | | | | | | | | | | | | | | | |
| 2020 | $ | 2,123 | | | $ | 1,133 | | | $ | 347 | | | $ | 550 | | | $ | 782 | | | $ | 79 | | | $ | 0 | | | $ | 5,014 | |
| 2019 | 1,535 | | | 1,033 | | | 333 | | | 502 | | | 754 | | | 95 | | | 0 | | | 4,252 | |
| 2018 | 1,797 | | | 940 | | | 301 | | | 483 | | | 740 | | | 92 | | | 0 | | | 4,353 | |
| Operating expenses: | | | | | | | | | | | | | | | |
| 2020 | $ | 17,358 | | | $ | 4,950 | | | $ | 2,512 | | | $ | 2,598 | | | $ | 4,045 | | | $ | 2,047 | | | $ | (3,270) | | | $ | 30,240 | |
| 2019 | 17,628 | | | 4,580 | | | 2,388 | | | 2,574 | | | 4,084 | | | 1,996 | | | (3,154) | | | 30,096 | |
| 2018 | 19,510 | | | 4,741 | | | 2,452 | | | 2,696 | | | 4,156 | | | 1,929 | | | (3,341) | | | 32,143 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Interest expense, net: | | | | | | | | | | | | | | | |
| 2020 | $ | 357 | | | $ | 382 | | | $ | 147 | | | $ | 133 | | | $ | 268 | | | $ | 351 | | | $ | (3) | | | $ | 1,635 | |
| 2019 | 429 | | | 359 | | | 136 | | | 121 | | | 263 | | | 308 | | | 0 | | | 1,616 | |
| 2018 | 432 | | | 347 | | | 129 | | | 106 | | | 261 | | | 279 | | | 0 | | | 1,554 | |
| Income (loss) before income taxes: | | | | | | | | | | | | | | | |
| 2020 | $ | 836 | | | $ | 615 | | | $ | 417 | | | $ | 390 | | | $ | 418 | | | $ | (343) | | | $ | 0 | | | $ | 2,333 | |
| 2019 | 1,917 | | | 851 | | | 593 | | | 439 | | | 514 | | | (327) | | | (2) | | | 3,985 | |
| 2018 | 365 | | | 832 | | | 466 | | | 387 | | | 425 | | | (249) | | | (1) | | | 2,225 | |
| Income taxes: | | | | | | | | | | | | | | | |
| 2020 | $ | 249 | | | $ | 177 | | | $ | (30) | | | $ | 41 | | | $ | (77) | | | $ | 13 | | | $ | 0 | | | $ | 373 | |
| 2019 | 516 | | | 163 | | | 65 | | | 79 | | | 38 | | | (87) | | | 0 | | | 774 | |
| 2018 | (108) | | | 168 | | | 6 | | | 74 | | | 33 | | | (55) | | | 0 | | | 118 | |
| Net income (loss): | | | | | | | | | | | | | | | |
| 2020 | $ | 579 | | | $ | 438 | | | $ | 447 | | | $ | 349 | | | $ | 495 | | | $ | (354) | | | $ | 0 | | | $ | 1,954 | |
| 2019 | 1,217 | | | 688 | | | 528 | | | 360 | | | 477 | | | (240) | | | (2) | | | 3,028 | |
|
| | | | | | | |
| | Year Ended December 31, |
| | 2016(a) | | 2015(b) |
| Total operating revenues | $ | 32,342 |
| | $ | 33,823 |
|
| Net income attributable to common shareholders | 1,562 |
| | 2,618 |
|
| | | | |
| Basic earnings per share | $ | 1.69 |
| | $ | 2.85 |
|
| Diluted earnings per share | 1.69 |
| | 2.84 |
|
______________
| |
(a) | The amounts above exclude non-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for the year ended December 31, 2016. |
| |
(b) | The amounts above exclude non-recurring costs directly related to the merger of $92 million and intercompany revenue of $559 million for the year ended December 31, 2015. |
On July 31, 2018, Generation entered into an agreement with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for the sale and decommissioning of the Oyster Creek Generating Station (Oyster Creek) located in Forked River, New Jersey. On September 17, 2018, Oyster Creek permanently ceased generation operations.
Under the terms of the transaction, Generation will transfer to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. In addition to the assumption of liability for the full decommissioning and ongoing management of spent fuel, other consideration to be received in the transaction is contingent on several factors, including a requirement that Generation deliver a minimum NDT fund balance at closing, subject to adjustment for specific terms that include income taxes that would be imposed on any net unrealized built-in gains and certain decommissioning activities to be performed during the pre-close period after the unit shuts down in the fall of 2018 and prior to the anticipated close of the transaction. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events.
As a result of the transaction, in 2018, Exelon and Generation reclassified certain Oyster Creek assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. At December 31, 2018 Generation has $897 million and $777 million of Assets held for sale and Liabilities held for sale, respectively, for Oyster Creek. Upon remeasurement of the Oyster Creek ARO in 2018, Exelon and Generation recognized an $84 million pre-tax charge to Operating and maintenance expense. See Note 15 -Asset Retirement Obligations for additional information.
Completion of the transaction contemplated by the sale agreement is subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and the receipt of a private letter ruling from the IRS. Generation currently anticipates satisfaction of the closing conditions to occur in the second half of 2019.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
Disposition | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
| 2018 | 443 | | | 664 | | | 460 | | | 313 | | | 393 | | | (193) | | | (1) | | | 2,079 | |
| Capital expenditures: | | | | | | | | | | | | | | | |
| 2020 | $ | 1,747 | | | $ | 2,217 | | | $ | 1,147 | | | $ | 1,247 | | | $ | 1,604 | | | $ | 86 | | | $ | 0 | | | $ | 8,048 | |
| 2019 | 1,845 | | | 1,915 | | | 939 | | | 1,145 | | | 1,355 | | | 49 | | | 0 | | | 7,248 | |
| 2018 | 2,242 | | | 2,126 | | | 849 | | | 959 | | | 1,375 | | | 43 | | | 0 | | | 7,594 | |
| Total assets: | | | | | | | | | | | | | | | |
| 2020 | $ | 48,094 | | | $ | 34,466 | | | $ | 12,531 | | | $ | 11,650 | | | $ | 23,736 | | | $ | 9,005 | | | $ | (10,165) | | | $ | 129,317 | |
| 2019 | 48,995 | | | 32,765 | | | 11,469 | | | 10,634 | | | 22,719 | | | 8,484 | | | (10,089) | | | 124,977 | |
__________
(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of EGTP and Acquisition of Handley Generating Station (Exelon and Generation)
EGTP, a Delaware limited liability company, was formedutility taxes to the governing bodies is recorded in 2014 with the purpose of financing a portfolio of assets comprised of two combined-cycle gas turbines (CCGTs) and three peaking/simple cycle facilities consisting of approximately 3.4 GW of generation capacity in ERCOT North and Houston Zones. EGTP was an indirect wholly owned subsidiary of Exelon and Generation.
EGTP’s operating cash flows were negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, as a result of the negative impacts of certain market conditions and the seasonality of its cash flows, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain of EGTP assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a $460 million pre-tax impairment loss. See Note 13 - Debt and Credit Agreements for details regarding the nonrecourse debt associated with EGTP and Note 7 - Impairment of Long-Lived Assets and Intangibles for additional information.
On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Codeexpenses in the United States Bankruptcy Court for the District of Delaware, which resulted in Exelon and Generation deconsolidating EGTP's assets and liabilities from their consolidated financial statements in the fourth quarter of 2017 that resulted in a pre-tax gain upon deconsolidation of $213 million. Concurrently with the Chapter 11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP's generating plants, the Handley Generating Station, subject to a potential adjustment for fuel oil and assumption of certain liabilities. In the Chapter 11 Filings, EGTP requested that the proposed acquisition of the Handley Generating Station be consummated through a court-approved and supervised sales process. The acquisition closed on April 4, 2018 for a purchase price of $62 million. The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders.
Other Asset Dispositions (Exelon, Generation, DPL and Pepco)
In December 2017, Generation entered into an agreement to sell its interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution systems. As a result, as of December 31, 2017, certain assets and liabilities were classified as held for sale and included in the Other current assets and Other current liabilities balances in Exelon's and Generation's Consolidated Balance Sheet. On February 28, 2018, Generation completed the sale of its interest for $87 million, resulting in a pre-tax gain which is included within Gain on sales of assets and businesses in Exelon's and Generation'sRegistrants’ Consolidated Statements of Operations and Comprehensive Income. In June 2018,See Note 24 — Supplemental Financial Information for additional proceeds were received,information on total utility taxes.
(c)Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and a pre-tax gain was recorded within Gain on salesservices by and between Exelon’s segments is not eliminated in consolidation due to the recognition of assets and businessesintersegment profit in Exelon's and Generation'saccordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
During the fourth quarter of 2016, as part of its continual assessment of growth and development opportunities, Generation reevaluated and in certain instances terminated or renegotiated certain projects and contracts. As a result, a pre-tax loss of $69 million was recorded within Loss on sales of assets and businesses and pre-tax impairment charges of $23 million was recorded within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
On June 16, 2016, Generation initiated the sales process of its Upstream business by executing a forbearance agreement with the lenders of the nonrecourse debt. See Note 1325 - Debt and Credit AgreementsRelated Party Transactions for additional information. In December 2016, Generation sold substantially allinformation on intersegment revenues.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
6. Property, Plant and Equipment (All Registrants)PHI:
Exelon
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pepco | | DPL | | ACE | | Other(a) | | Intersegment
Eliminations | | PHI |
Operating revenues(b): | | | | | | | | | | | |
| 2020 | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 2,149 | | | $ | 1,109 | | | $ | 1,245 | | | $ | 0 | | | $ | (18) | | | $ | 4,485 | |
| Rate-regulated natural gas revenues | 0 | | | 162 | | | 0 | | | 0 | | | 0 | | | 162 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 372 | | | (356) | | | 16 | |
| Total operating revenues | $ | 2,149 | | | $ | 1,271 | | | $ | 1,245 | | | $ | 372 | | | $ | (374) | | | $ | 4,663 | |
| 2019 | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 2,260 | | | $ | 1,139 | | | $ | 1,240 | | | $ | 0 | | | $ | (13) | | | $ | 4,626 | |
| Rate-regulated natural gas revenues | 0 | | | 167 | | | 0 | | | 0 | | | 0 | | | 167 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 396 | | | (383) | | | 13 | |
| Total operating revenues | $ | 2,260 | | | $ | 1,306 | | | $ | 1,240 | | | $ | 396 | | | $ | (396) | | | $ | 4,806 | |
| 2018 | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 2,232 | | | $ | 1,151 | | | $ | 1,236 | | | $ | 0 | | | $ | (17) | | | $ | 4,602 | |
| Rate-regulated natural gas revenues | 0 | | | 181 | | | 0 | | | 0 | | | 0 | | | 181 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 435 | | | (420) | | | 15 | |
| Total operating revenues | $ | 2,232 | | | $ | 1,332 | | | $ | 1,236 | | | $ | 435 | | | $ | (437) | | | $ | 4,798 | |
Intersegment revenues(c): | | | | | | | | | | | |
| 2020 | $ | 7 | | | $ | 9 | | | $ | 4 | | | $ | 372 | | | $ | (375) | | | $ | 17 | |
| 2019 | 5 | | | 7 | | | 3 | | | 396 | | | (397) | | | 14 | |
| 2018 | 6 | | | 8 | | | 3 | | | 435 | | | (437) | | | 15 | |
| Depreciation and amortization: | | | | | | | | | | | |
| 2020 | $ | 377 | | | $ | 191 | | | $ | 180 | | | $ | 34 | | | $ | 0 | | | $ | 782 | |
| 2019 | 374 | | | 184 | | | 157 | | | 39 | | | 0 | | | 754 | |
| 2018 | 385 | | | 182 | | | 136 | | | 37 | | | 0 | | | 740 | |
| Operating expenses: | | | | | | | | | | | |
| 2020 | $ | 1,799 | | | $ | 1,120 | | | $ | 1,123 | | | $ | 378 | | | $ | (375) | | | $ | 4,045 | |
| 2019 | 1,899 | | | 1,089 | | | 1,089 | | | 403 | | | (396) | | | 4,084 | |
| 2018 | 1,919 | | | 1,143 | | | 1,087 | | | 442 | | | (435) | | | 4,156 | |
| Interest expense, net: | | | | | | | | | | | |
| 2020 | $ | 138 | | | $ | 61 | | | $ | 59 | | | $ | 10 | | | $ | 0 | | | $ | 268 | |
| 2019 | 133 | | | 61 | | | 58 | | | 10 | | | 1 | | | 263 | |
| 2018 | 128 | | | 58 | | | 64 | | | 11 | | | 0 | | | 261 | |
| Income (loss) before income taxes: | | | | | | | | | | | |
| 2020 | $ | 259 | | | $ | 100 | | | $ | 71 | | | $ | (12) | | | $ | 0 | | | $ | 418 | |
2019(d) | 259 | | | 169 | | | 99 | | | (13) | | | 0 | | | 514 | |
2018(d) | 216 | | | 142 | | | 87 | | | (20) | | | 0 | | | 425 | |
| Income taxes: | | | | | | | | | | | |
| 2020 | $ | (7) | | | $ | (25) | | | $ | (41) | | | $ | (4) | | | $ | 0 | | | $ | (77) | |
| 2019 | 16 | | | 22 | | | 0 | | | 0 | | | 0 | | | 38 | |
| 2018 | 11 | | | 22 | | | 12 | | | (12) | | | 0 | | | 33 | |
|
| | | | | | | | | |
| | Average Service Life (years) | | 2018 | | 2017 |
| Asset Category | | | | | |
| Electric—transmission and distribution | 5-90 | | $ | 53,090 |
| | $ | 49,506 |
|
| Electric—generation | 1-56 | | 29,170 |
| | 29,019 |
|
| Gas—transportation and distribution | 5-90 | | 5,530 |
| | 5,050 |
|
| Common—electric and gas | 5-75 | | 1,627 |
| | 1,447 |
|
Nuclear fuel (a) | 1-8 | | 5,957 |
| | 6,420 |
|
| Construction work in progress | N/A | | 3,377 |
| | 2,825 |
|
Other property, plant and equipment (b) | 1-50 | | 858 |
| | 999 |
|
| Total property, plant and equipment | | | 99,609 |
| | 95,266 |
|
Less: accumulated depreciation (c) | | | 22,902 |
| | 21,064 |
|
| Property, plant and equipment, net | | | $ | 76,707 |
| | $ | 74,202 |
|
__________
| |
(a) | Includes nuclear fuel that is in the fabrication and installation phase of $1,004 million and $1,196 million at December 31, 2018 and 2017, respectively. |
| |
(b) | Includes Generation’s buildings under capital lease with a net carrying value of $5 million and $7 million at December 31, 2018 and 2017, respectively. The original cost basis of the buildings was $47 million as of both December 31, 2018 and 2017, and total accumulated amortization was $42 million and $40 million, as of December 31, 2018 and 2017, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2018 and 2017 of $7 million. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million as of both December 31, 2018 and 2017. Includes land held for future use and non-utility property at ComEd, PECO, BGE, Pepco, DPL and ACE of $39 million, $19 million, $25 million, $61 million, $17 million and $28 million, respectively, at December 31, 2018. |
| |
(c) | Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,969 million and $3,159 million as of December 31, 2018 and 2017, respectively. |
|
| | | | | | | | |
| Average Service Life Percentage by Asset Category | 2018 | | 2017 | | 2016 |
| Electric—transmission and distribution | 2.73 | % | | 2.75 | % | | 2.73 | % |
Electric—generation(a) | 5.37 | % | | 4.36 | % | | 5.94 | % |
| Gas | 2.07 | % | | 2.10 | % | | 2.17 | % |
| Common—electric and gas | 6.98 | % | | 7.05 | % | | 7.41 | % |
__________
| |
(a) | See Note 8 — Early Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton, Quad Cities, Oyster Creek and TMI. |
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:
Note 5 — Segment Information
|
| | | | | | | | | |
| | Average Service Life (years) | | 2018 | | 2017 |
| Asset Category | | | | | |
| Electric—generation | 1-56 | | $ | 29,170 |
| | $ | 29,019 |
|
Nuclear fuel (a) | 1-8 | | 5,957 |
| | 6,420 |
|
| Construction work in progress | N/A | | 997 |
| | 838 |
|
Other property, plant and equipment (b) | 1-8 | | 63 |
| | 57 |
|
| Total property, plant and equipment | | | 36,187 |
| | 36,334 |
|
Less: accumulated depreciation (c) | | | 12,206 |
| | 11,428 |
|
| Property, plant and equipment, net | | | $ | 23,981 |
| | $ | 24,906 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pepco | | DPL | | ACE | | Other(a) | | Intersegment
Eliminations | | PHI |
| Net income (loss): | | | | | | | | | | | |
| 2020 | $ | 266 | | | $ | 125 | | | $ | 112 | | | $ | (8) | | | $ | 0 | | | $ | 495 | |
| 2019 | 243 | | | 147 | | | 99 | | | (12) | | | 0 | | | 477 | |
| 2018 | 205 | | | 120 | | | 75 | | | (7) | | | 0 | | | 393 | |
| Capital expenditures: | | | | | | | | | | | |
| 2020 | $ | 773 | | | $ | 424 | | | $ | 401 | | | $ | 6 | | | $ | 0 | | | $ | 1,604 | |
| 2019 | 626 | | | 348 | | | 375 | | | 6 | | | 0 | | | 1,355 | |
| 2018 | 656 | | | 364 | | | 335 | | | 20 | | | 0 | | | 1,375 | |
| Total assets: | | | | | | | | | | | |
| 2020 | $ | 9,264 | | | $ | 5,140 | | | $ | 4,286 | | | $ | 5,079 | | | $ | (33) | | | $ | 23,736 | |
2019(d) | 8,661 | | | 4,830 | | | 3,933 | | | 5,335 | | | (40) | | | 22,719 | |
__________
| |
(a) | Includes nuclear fuel that is in the fabrication and installation phase of $1,004 million and $1,196 million at December 31, 2018 and 2017, respectively. |
| |
(b) | Includes buildings under capital lease with a net carrying value of $5 million and $7 million at December 31, 2018 and 2017, respectively. The original cost basis of the buildings was $47 million as of both December 31, 2018 and 2017, and total accumulated amortization was $42 million and $40 million, as of December 31, 2018 and 2017, respectively. |
| |
(c) | Includes accumulated amortization of nuclear fuel in the reactor core of $2,969 million and $3,159 million as of December 31, 2018 and 2017, respectively. |
(a)Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The annual depreciation provisions as a percentageoffsetting remittance of average service life for electric generation assets were 5.37%, 4.36% and 5.94% forutility taxes to the years ended December 31, 2018, 2017 and 2016, respectively. See Note 8 — Early Plant Retirements for additional information on the accelerated depreciation and amortization of Clinton, Quad Cities, Oyster Creek and TMI.
License Renewals
Depreciation provisions are based on the estimated useful lives of the stations, which reflect the actual renewal of the operating licenses for all of Generation's operating nuclear generating stations except for TMI and Clinton. As a result, the receipt of license renewals has no material impactgoverning bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. Beginning in 2017, TMI and Oyster Creek depreciation provisions were based on their 2019 expected shutdown dates. Beginning February 2018, Oyster Creek depreciation provisions were based on its announced shutdown date of September 2018. Clinton depreciation provisions are based on an estimated useful life through 2027 which is the last year of the Illinois Zero Emissions Standard. See Note 424 — Regulatory Matters for additional information regarding license renewals and the Illinois ZECs and Note 8 — Early Plant RetirementsSupplemental Financial Information for additional information on total utility taxes.
(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.
(d)The Income (loss) before income taxes in Other and Intersegment Eliminations have been adjusted by an offsetting $489 million and $408 million in 2019 and 2018, respectively, and Total assets amounts in Other and Intersegment Eliminations have been adjusted by an offsetting $5.7 billion in 2019 for consistency with the impactsExelon consolidating disclosure above.
The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of expectedrevenue and potential early plant retirement.cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation's two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon's disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.
Competitive Business Revenues (Generation):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 |
| Revenues from external customers(a) | | | | |
| | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues |
| Mid-Atlantic | $ | 4,785 | | | $ | (168) | | | $ | 4,617 | | | $ | 28 | | | $ | 4,645 | |
| Midwest | 3,717 | | | 312 | | | 4,029 | | | (5) | | | 4,024 | |
| New York | 1,444 | | | (12) | | | 1,432 | | | (1) | | | 1,431 | |
| ERCOT | 735 | | | 198 | | | 933 | | | 25 | | | 958 | |
| Other Power Regions | 3,586 | | | 463 | | | 4,049 | | | (47) | | | 4,002 | |
| Total Competitive Businesses Electric Revenues | $ | 14,267 | | | $ | 793 | | | $ | 15,060 | | | $ | 0 | | | $ | 15,060 | |
| Competitive Businesses Natural Gas Revenues | 1,283 | | | 720 | | | 2,003 | | | 0 | | | 2,003 | |
Competitive Businesses Other Revenues(c) | 355 | | | 185 | | | 540 | | | 0 | | | 540 | |
| Total Generation Consolidated Operating Revenues | $ | 15,905 | | | $ | 1,698 | | | $ | 17,603 | | | $ | 0 | | | $ | 17,603 | |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:
Note 5 — Segment Information
|
| | | | | | | | | |
| | Average Service Life (years) | | 2018 | | 2017 |
| Asset Category | | | | | |
| Electric—transmission and distribution | 5-80 | | $ | 25,991 |
| | $ | 24,423 |
|
| Construction work in progress | N/A | | 705 |
| | 517 |
|
Other property, plant and equipment (a), (b) | 35-50 | | 46 |
| | 52 |
|
| Total property, plant and equipment | | | 26,742 |
| | 24,992 |
|
| Less: accumulated depreciation | | | 4,684 |
| | 4,269 |
|
| Property, plant and equipment, net | | | $ | 22,058 |
| | $ | 20,723 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2019 |
| Revenues from external customers(a) | | | | |
| | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues |
| Mid-Atlantic | $ | 5,053 | | | $ | 17 | | | $ | 5,070 | | | $ | 4 | | | $ | 5,074 | |
| Midwest | 4,095 | | | 232 | | | 4,327 | | | (34) | | | 4,293 | |
| New York | 1,571 | | | 25 | | | 1,596 | | | 0 | | | 1,596 | |
| ERCOT | 768 | | | 229 | | | 997 | | | 16 | | | 1,013 | |
| Other Power Regions | 3,687 | | | 608 | | | 4,295 | | | (49) | | | 4,246 | |
| Total Competitive Businesses Electric Revenues | $ | 15,174 | | | $ | 1,111 | | | $ | 16,285 | | | $ | (63) | | | $ | 16,222 | |
| Competitive Businesses Natural Gas Revenues | 1,446 | | | 702 | | | 2,148 | | | 62 | | | 2,210 | |
Competitive Businesses Other Revenues(c) | 440 | | | 51 | | | 491 | | | 1 | | | 492 | |
| Total Generation Consolidated Operating Revenues | $ | 17,060 | | | $ | 1,864 | | | $ | 18,924 | | | $ | 0 | | | $ | 18,924 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 |
| Revenues from external customers(a) | | | | |
| | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues |
| Mid-Atlantic | $ | 5,241 | | | $ | 233 | | | $ | 5,474 | | | $ | 13 | | | $ | 5,487 | |
| Midwest | 4,527 | | | 190 | | | 4,717 | | | (11) | | | 4,706 | |
| New York | 1,723 | | | (36) | | | 1,687 | | | 0 | | | 1,687 | |
| ERCOT | 572 | | | 560 | | | 1,132 | | | 1 | | | 1,133 | |
| Other Power Regions | 3,530 | | | 871 | | | 4,401 | | | (66) | | | 4,335 | |
| Total Competitive Businesses Electric Revenues | $ | 15,593 | | | $ | 1,818 | | | $ | 17,411 | | | $ | (63) | | | $ | 17,348 | |
| Competitive Businesses Natural Gas Revenues | 1,524 | | | 1,194 | | | 2,718 | | | 62 | | | 2,780 | |
Competitive Businesses Other Revenues(c) | 510 | | | (202) | | | 308 | | | 1 | | | 309 | |
| Total Generation Consolidated Operating Revenues | $ | 17,627 | | | $ | 2,810 | | | $ | 20,437 | | | $ | 0 | | | $ | 20,437 | |
__________
| |
(a) | Includes buildings under capital lease with a net carrying value at both December 31, 2018 and 2017 of $7 million. The original cost basis of the buildings was $8(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants. (b)Includes revenues from derivatives and leases. (c)Represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $110 million and losses of $4 million and $262 million and total accumulated amortization was $1 million as of both December 31, 2018 and 2017. |
| |
(b) | Represents land held for future use and non-utility property. |
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.95%, 2.99% and 3.03% for the years ended December 31, 2020, 2019, and 2018, 2017respectively, and 2016, respectively.
PECO
The following table presents a summarythe elimination of property, plant and equipment by asset category as of December 31, 2018 and 2017:intersegment revenues.
|
| | | | | | | | | |
| | Average Service Life (years) | | 2018 | | 2017 |
| Asset Category | | | | | |
| Electric—transmission and distribution | 5-65 | | $ | 8,359 |
| | $ | 7,975 |
|
| Gas—transportation and distribution | 5-70 | | 2,694 |
| | 2,504 |
|
| Common—electric and gas | 5-50 | | 756 |
| | 710 |
|
| Construction work in progress | N/A | | 343 |
| | 254 |
|
Other property, plant and equipment (a) | 50 | | 19 |
| | 21 |
|
| Total property, plant and equipment | | | 12,171 |
| | 11,464 |
|
| Less: accumulated depreciation | | | 3,561 |
| | 3,411 |
|
| Property, plant and equipment, net | | | $ | 8,610 |
| | $ | 8,053 |
|
__________
| |
(a) | Represents land held for future use and non-utility property. |
|
| | | | | | | | |
| Average Service Life Percentage by Asset Category | 2018 | | 2017 | | 2016 |
| Electric—transmission and distribution | 2.35 | % | | 2.37 | % | | 2.32 | % |
| Gas | 1.90 | % | | 1.89 | % | | 1.82 | % |
| Common—electric and gas | 5.44 | % | | 5.47 | % | | 5.11 | % |
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
BGERevenues net of purchased power and fuel expense (Generation):
The following table presents | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | RNF from external
customers(a) | | Intersegment
RNF | | Total
RNF | | RNF from external
customers(a) | | Intersegment
RNF | | Total
RNF | | RNF from external
customers(a) | | Intersegment
RNF | | Total
RNF |
| Mid-Atlantic | $ | 2,174 | | | $ | 30 | | | $ | 2,204 | | | $ | 2,637 | | | $ | 18 | | | $ | 2,655 | | | $ | 3,022 | | | $ | 51 | | | $ | 3,073 | |
| Midwest | 2,902 | | | 0 | | | 2,902 | | | 2,994 | | | (32) | | | 2,962 | | | 3,112 | | | 23 | | | 3,135 | |
| New York | 983 | | | 14 | | | 997 | | | 1,081 | | | 13 | | | 1,094 | | | 1,112 | | | 10 | | | 1,122 | |
| ERCOT | 407 | | | 19 | | | 426 | | | 338 | | | (30) | | | 308 | | | 501 | | | (243) | | | 258 | |
| Other Power Regions | 759 | | | (94) | | | 665 | | | 694 | | | (74) | | | 620 | | | 883 | | | (154) | | | 729 | |
| Total RNF for Reportable Segments | $ | 7,225 | | | $ | (31) | | | $ | 7,194 | | | $ | 7,744 | | | $ | (105) | | | $ | 7,639 | | | $ | 8,630 | | | $ | (313) | | | $ | 8,317 | |
Other(b) | 793 | | | 31 | | | 824 | | | 324 | | | 105 | | | 429 | | | 114 | | | 313 | | | 427 | |
| Total Generation RNF | $ | 8,018 | | | $ | 0 | | | $ | 8,018 | | | $ | 8,068 | | | $ | 0 | | | $ | 8,068 | | | $ | 8,744 | | | $ | 0 | | | $ | 8,744 | |
__________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a summaryregion. See text above for a description of property, plant included activities. Primarily includes:
•unrealized mark-to-market gains of $295 million and equipment by asset category aslosses of $215 million and $319 million for the years ended December 31, 2020, 2019, and 2018, respectively;
•accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $60 million, $13 million, and 2017:
|
| | | | | | | | | |
| | Average Service Life (years) | | 2018 | | 2017 |
| Asset Category | | | | | |
| Electric—transmission and distribution | 5-90 | | $ | 7,951 |
| | $ | 7,464 |
|
| Gas—distribution | 5-90 | | 2,630 |
| | 2,379 |
|
| Common—electric and gas | 5-40 | | 860 |
| | 771 |
|
| Construction work in progress | N/A | | 410 |
| | 367 |
|
Other property, plant and equipment (a) | 20 | | 25 |
| | 26 |
|
| Total property, plant and equipment | | | 11,876 |
| | 11,007 |
|
| Less: accumulated depreciation | | | 3,633 |
| | 3,405 |
|
| Property, plant and equipment, net | | | $ | 8,243 |
| | $ | 7,602 |
|
__________
| |
(a) | Represents plant held$57 million in for future use and non-utility property. |
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
|
| | | | | | | | |
| Average Service Life Percentage by Asset Category | 2018 | | 2017 | | 2016 |
| Electric—transmission and distribution | 2.61 | % | | 2.58 | % | | 2.56 | % |
| Gas | 2.36 | % | | 2.33 | % | | 2.45 | % |
| Common—electric and gas | 8.50 | % | | 8.64 | % | | 9.45 | % |
PHI
The following table presents a summary of property, plant and equipment by asset category as ofyears ended December 31, 2020, 2019, and 2018, respectively; and 2017:
•the elimination of intersegment RNF.
|
| | | | | | | | | |
| | Average
Service Life
(years) | | 2018 | | 2017 |
| Asset Category | | | | | |
| Electric—transmission and distribution | 5-75 | | $ | 12,664 |
| | $ | 11,517 |
|
| Gas—distribution | 5-75 | | 486 |
| | 449 |
|
| Common—electric and gas | 5-75 | | 126 |
| | 82 |
|
| Construction work in progress | N/A | | 912 |
| | 835 |
|
Other property, plant and equipment (a) | 3-43 | | 99 |
| | 102 |
|
| Total property, plant and equipment | | | 14,287 |
|
| 12,985 |
|
| Less: accumulated depreciation | | | 841 |
| | 487 |
|
| Property, plant and equipment, net | | | $ | 13,446 |
|
| $ | 12,498 |
|
__________
| |
(a) | Represents plant held for future use and non-utility property. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.Electric and Gas Revenue by Customer Class (Utility Registrants):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2020 |
| | | | | | | | | | | | | |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 3,090 | | | $ | 1,656 | | | $ | 1,345 | | | $ | 2,332 | | | $ | 988 | | | $ | 652 | | | $ | 692 | |
| Small commercial & industrial | 1,399 | | | 386 | | | 241 | | | 472 | | | 132 | | | 171 | | | 169 | |
| Large commercial & industrial | 515 | | | 228 | | | 406 | | | 1,001 | | | 736 | | | 89 | | | 176 | |
| Public authorities & electric railroads | 45 | | | 29 | | | 27 | | | 60 | | | 34 | | | 13 | | | 13 | |
Other(a) | 884 | | | 225 | | | 309 | | | 613 | | | 218 | | | 190 | | | 207 | |
Total rate-regulated electric revenues(b) | $ | 5,933 | | | $ | 2,524 | | | $ | 2,328 | | | $ | 4,478 | | | $ | 2,108 | | | $ | 1,115 | | | $ | 1,257 | |
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | 0 | | | $ | 361 | | | $ | 504 | | | $ | 96 | | | $ | 0 | | | $ | 96 | | | $ | 0 | |
| Small commercial & industrial | 0 | | | 126 | | | 79 | | | 42 | | | 0 | | | 42 | | | 0 | |
| Large commercial & industrial | 0 | | | 0 | | | 135 | | | 4 | | | 0 | | | 4 | | | 0 | |
| Transportation | 0 | | | 24 | | | 0 | | | 14 | | | 0 | | | 14 | | | 0 | |
Other(c) | 0 | | | 4 | | | 29 | | | 6 | | | 0 | | | 6 | | | 0 | |
Total rate-regulated natural gas revenues(d) | $ | 0 | | | $ | 515 | | | $ | 747 | | | $ | 162 | | | $ | 0 | | | $ | 162 | | | $ | 0 | |
| Total rate-regulated revenues from contracts with customers | $ | 5,933 | | | $ | 3,039 | | | $ | 3,075 | | | $ | 4,640 | | | $ | 2,108 | | | $ | 1,277 | | | $ | 1,257 | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (47) | | | $ | 16 | | | $ | 16 | | | $ | 21 | | | $ | 40 | | | $ | (7) | | | $ | (12) | |
Other rate-regulated electric revenues(e) | 18 | | | 3 | | | 5 | | | 2 | | | 1 | | | 1 | | | 0 | |
Other rate-regulated natural gas revenues(e) | 0 | | | 0 | | | 2 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | |
| Total other revenues | $ | (29) | | | $ | 19 | | | $ | 23 | | | $ | 23 | | | $ | 41 | | | $ | (6) | | | $ | (12) | |
| Total rate-regulated revenues for reportable segments | $ | 5,904 | | | $ | 3,058 | | | $ | 3,098 | | | $ | 4,663 | | | $ | 2,149 | | | $ | 1,271 | | | $ | 1,245 | |
|
| | | | | | | | |
| Average Service Life Percentage by Asset Category | 2018 | | 2017 | | 2016 |
| Electric—transmission and distribution | 2.61 | % | | 2.63 | % | | 2.52 | % |
| Gas | 1.59 | % | | 2.07 | % | | 2.57 | % |
| Common—electric and gas | 6.30 | % | | 6.50 | % | | 8.12 | % |
Pepco
|
| | | | | | | | | |
| | Average Service Life (years) | | 2018 | | 2017 |
| Asset Category | | | | | |
| Electric—transmission and distribution | 5-75 | | $ | 9,217 |
| | $ | 8,646 |
|
| Construction work in progress | N/A | | 536 |
| | 473 |
|
Other property, plant and equipment (a) | 25-33 | | 61 |
| | 59 |
|
| Total property, plant and equipment | | | 9,814 |
|
| 9,178 |
|
| Less: accumulated depreciation | | | 3,354 |
| | 3,177 |
|
| Property, plant and equipment, net | | | $ | 6,460 |
|
| $ | 6,001 |
|
__________
| |
(a) | Represents plant held for future use and non-utility property. |
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.40%, 2.35% and 2.17% for the years ended December 31, 2018, 2017 and 2016, respectively.
DPL
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:
|
| | | | | | | | | |
| | Average Service Life (years) | | 2018 | | 2017 |
| Asset Category | | | | | |
| Electric—transmission and distribution | 5-70 | | $ | 4,195 |
| | $ | 3,875 |
|
| Gas—distribution | 5-75 | | 651 |
| | 614 |
|
| Common—electric and gas | 5-75 | | 136 |
| | 117 |
|
| Construction work in progress | N/A | | 151 |
| | 205 |
|
Other property, plant and equipment (a) | 10-43 | | 17 |
| | 15 |
|
| Total property, plant and equipment | | | 5,150 |
|
| 4,826 |
|
| Less: accumulated depreciation | | | 1,329 |
| | 1,247 |
|
| Property, plant and equipment, net | | | $ | 3,821 |
|
| $ | 3,579 |
|
__________
| |
(a) | Represents plant held for future use and non-utility property. |
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2019 |
| | | | | | | | | | | | | |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 2,916 | | | $ | 1,596 | | | $ | 1,326 | | | $ | 2,316 | | | $ | 1,012 | | | $ | 645 | | | $ | 659 | |
| Small commercial & industrial | 1,463 | | | 404 | | | 254 | | | 505 | | | 149 | | | 186 | | | 170 | |
| Large commercial & industrial | 540 | | | 219 | | | 436 | | | 1,112 | | | 833 | | | 99 | | | 180 | |
| Public authorities & electric railroads | 47 | | | 29 | | | 27 | | | 61 | | | 34 | | | 14 | | | 13 | |
Other(a) | 888 | | | 249 | | | 321 | | | 650 | | | 227 | | | 204 | | | 218 | |
Total rate-regulated electric revenues(b) | $ | 5,854 | | | $ | 2,497 | | | $ | 2,364 | | | $ | 4,644 | | | $ | 2,255 | | | $ | 1,148 | | | $ | 1,240 | |
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | 0 | | | $ | 409 | | | $ | 474 | | | $ | 96 | | | $ | 0 | | | $ | 96 | | | $ | 0 | |
| Small commercial & industrial | 0 | | | 169 | | | 77 | | | 44 | | | 0 | | | 45 | | | 0 | |
| Large commercial & industrial | 0 | | | 1 | | | 132 | | | 5 | | | 0 | | | 5 | | | 0 | |
| Transportation | 0 | | | 25 | | | 0 | | | 14 | | | 0 | | | 14 | | | 0 | |
Other(c) | 0 | | | 6 | | | 31 | | | 7 | | | 0 | | | 7 | | | 0 | |
Total rate-regulated natural gas revenues(d) | $ | 0 | | | $ | 610 | | | $ | 714 | | | $ | 166 | | | $ | 0 | | | $ | 167 | | | $ | 0 | |
| Total rate-regulated revenues from contracts with customers | $ | 5,854 | | | $ | 3,107 | | | $ | 3,078 | | | $ | 4,810 | | | $ | 2,255 | | | $ | 1,315 | | | $ | 1,240 | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (133) | | | $ | (21) | | | $ | 12 | | | $ | (14) | | | $ | (3) | | | $ | (11) | | | $ | 0 | |
Other rate-regulated electric revenues(e) | 26 | | | 13 | | | 12 | | | 10 | | | 8 | | | 2 | | | 0 | |
Other rate-regulated natural gas revenues(e) | 0 | | | 1 | | | 4 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | |
| Total other revenues | $ | (107) | | | $ | (7) | | | $ | 28 | | | $ | (4) | | | $ | 5 | | | $ | (9) | | | $ | 0 | |
| Total rate-regulated revenues for reportable segments | $ | 5,747 | | | $ | 3,100 | | | $ | 3,106 | | | $ | 4,806 | | | $ | 2,260 | | | $ | 1,306 | | | $ | 1,240 | |
|
| | | | | | | | |
| Average Service Life Percentage by Asset Category | 2018 | | 2017 | | 2016 |
| Electric—transmission and distribution | 2.77 | % | | 2.75 | % | | 2.49 | % |
| Gas | 1.59 | % | | 2.07 | % | | 2.57 | % |
| Common—electric and gas | 3.70 | % | | 4.14 | % | | 4.99 | % |
ACE
|
| | | | | | | | | |
| | Average Service Life (years) | | 2018 | | 2017 |
| Asset Category | | | | | |
| Electric—transmission and distribution | 5-60 | | $ | 3,866 |
| | $ | 3,607 |
|
| Construction work in progress | N/A | | 209 |
| | 138 |
|
Other property, plant and equipment (a) | 13-15 | | 28 |
| | 27 |
|
| Total property, plant and equipment | | | 4,103 |
|
| 3,772 |
|
| Less: accumulated depreciation | | | 1,137 |
| | 1,066 |
|
| Property, plant and equipment, net | | | $ | 2,966 |
|
| $ | 2,706 |
|
__________
| |
(a) | Represents plant held for future use and non-utility property. |
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.45%, 2.46% and 2.45% for the years ended December 31, 2018, 2017 and 2016, respectively.
Capitalized Software Costs (All Registrants)
The following tables presents net unamortized capitalized software costs and amortization of capitalized software costs by year.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net unamortized software costs | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| December 31, 2018 | $ | 810 |
| | $ | 164 |
| | $ | 206 |
| | $ | 98 |
| | $ | 166 |
| | $ | 165 |
| | $ | 26 |
| | $ | 21 |
| | $ | 14 |
|
| December 31, 2017 | 834 |
| | 173 |
| | 227 |
| | 111 |
| | 179 |
| | 133 |
| | 2 |
| | 1 |
| | 1 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of capitalized software costs | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
| 2018 | $ | 282 |
| | $ | 78 |
| | $ | 79 |
| | $ | 37 |
| | $ | 48 |
| | $ | 2 |
| | $ | 2 |
| | $ | 1 |
|
| 2017 | 270 |
| | 73 |
| | 73 |
| | 39 |
| | 46 |
| | — |
| | — |
| | — |
|
| 2016 | 255 |
| | 72 |
| | 62 |
| | 33 |
| | 44 |
| | — |
| | — |
| | — |
|
|
| | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| PHI | For the year ended December 31, 2018 | | For the year ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Amortization of capitalized software costs | $ | 33 |
| | $ | 34 |
| | $ | 29 |
| | | $ | 8 |
|
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Capitalized Interest and AFUDC (All Registrants)
The following table summarizes total incurred interest, capitalized interest and credits to AFUDC by year:
Note 5 — Segment Information
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
| 2018 | Total incurred interest(a) | $ | 1,695 |
| | $ | 464 |
| | $ | 377 |
| | $ | 141 |
| | $ | 130 |
| | $ | 162 |
| | $ | 62 |
| | $ | 68 |
|
| | Capitalized interest | 31 |
| | 31 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| | Credits to AFUDC debt and equity | 109 |
| | — |
| | 30 |
| | 12 |
| | 24 |
| | 34 |
| | 4 |
| | 4 |
|
| 2017 | Total incurred interest(a) | $ | 1,658 |
| | $ | 502 |
| | $ | 369 |
| | $ | 130 |
| | $ | 111 |
| | $ | 133 |
| | $ | 54 |
| | $ | 64 |
|
| | Capitalized interest | 63 |
| | 63 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| | Credits to AFUDC debt and equity | 108 |
| | — |
| | 20 |
| | 12 |
| | 22 |
| | 34 |
| | 10 |
| | 9 |
|
| 2016 | Total incurred interest(a) | $ | 1,678 |
| | $ | 472 |
| | $ | 469 |
| | $ | 127 |
| | $ | 114 |
| | $ | 137 |
| | $ | 52 |
| | $ | 65 |
|
| | Capitalized interest | 108 |
| | 107 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| | Credits to AFUDC debt and equity | 98 |
| | — |
| | 22 |
| | 11 |
| | 30 |
| | 29 |
| | 7 |
| | 9 |
|
|
| | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| PHI | For the year ended December 31, 2018 | | For the year ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
Total incurred interest(a) | $ | 305 |
| | $ | 263 |
| | $ | 207 |
| | | $ | 68 |
|
| Credits to AFUDC debt and equity | 44 |
| | 54 |
| | 35 |
| | | 10 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2018 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 2,942 | | | $ | 1,566 | | | $ | 1,382 | | | $ | 2,351 | | | $ | 1,021 | | | $ | 669 | | | $ | 661 | |
| Small commercial & industrial | 1,487 | | | 404 | | | 257 | | | 488 | | | 140 | | | 186 | | | 162 | |
| Large commercial & industrial | 538 | | | 223 | | | 429 | | | 1,124 | | | 846 | | | 100 | | | 178 | |
| Public authorities & electric railroads | 47 | | | 28 | | | 28 | | | 58 | | | 32 | | | 14 | | | 12 | |
Other(a) | 867 | | | 243 | | | 327 | | | 593 | | | 193 | | | 175 | | | 227 | |
Total rate-regulated electric revenues(b) | $ | 5,881 | | | $ | 2,464 | | | $ | 2,423 | | | $ | 4,614 | | | $ | 2,232 | | | $ | 1,144 | | | $ | 1,240 | |
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | 0 | | | $ | 395 | | | $ | 491 | | | $ | 99 | | | $ | 0 | | | $ | 99 | | | $ | 0 | |
| Small commercial & industrial | 0 | | | 143 | | | 77 | | | 44 | | | 0 | | | 44 | | | 0 | |
| Large commercial & industrial | 0 | | | 1 | | | 124 | | | 8 | | | 0 | | | 8 | | | 0 | |
| Transportation | 0 | | | 23 | | | 0 | | | 16 | | | 0 | | | 16 | | | 0 | |
Other(c) | 0 | | | 6 | | | 63 | | | 13 | | | 0 | | | 13 | | | 0 | |
Total rate-regulated natural gas revenues(d) | $ | 0 | | | $ | 568 | | | $ | 755 | | | $ | 180 | | | $ | 0 | | | $ | 180 | | | $ | 0 | |
| Total rate-regulated revenues from contracts with customers | $ | 5,881 | | | $ | 3,032 | | | $ | 3,178 | | | $ | 4,794 | | | $ | 2,232 | | | $ | 1,324 | | | $ | 1,240 | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (29) | | | $ | (7) | | | $ | (26) | | | $ | (7) | | | $ | (7) | | | $ | 4 | | | $ | (4) | |
Other rate-regulated electric revenues(e) | 30 | | | 12 | | | 13 | | | 10 | | | 7 | | | 3 | | | 0 | |
Other rate-regulated natural gas revenues(e) | 0 | | | 1 | | | 4 | | | 1 | | | 0 | | | 1 | | | 0 | |
| | | | | | | | | | | | | |
| Total other revenues | $ | 1 | | | $ | 6 | | | $ | (9) | | | $ | 4 | | | $ | 0 | | | $ | 8 | | | $ | (4) | |
| Total rate-regulated revenues for reportable segments | $ | 5,882 | | | $ | 3,038 | | | $ | 3,169 | | | $ | 4,798 | | | $ | 2,232 | | | $ | 1,332 | | | $ | 1,236 | |
__________
| |
(a) | Includes interest expense to affiliates. |
See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 13 — Debt and Credit Agreements for additional information regarding Exelon’s, ComEd’s and PECO’s property, plant and equipment subject to mortgage liens.
7. Impairment of Long-Lived Assets and Intangibles (Exelon, Generation and PHI)
Long-Lived Assets (Exelon, Generation and PHI)
Registrants evaluate long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In the second quarter of 2018, updates to Exelon's long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair value of the group were less than its carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and generation forecasts, projected capitalmutual assistance revenue.
(b)Includes operating revenues from affiliates in 2020, 2019, and maintenance expenditures2018 respectively of:
•$37 million, $30 million, and discount rates. As a result, long-lived merchant wind assets held$27 million at ComEd
•$8 million, $5 million, and used with a net carrying amount$7 million at PECO
•$10 million, $8 million, and $8 million at BGE
•$17 million, $14 million, and $15 million at PHI
•$7 million, $5 million, and $6 million at Pepco
•$9 million, $7 million, and $8 million at DPL
•$4 million, $3 million, and $3 million at ACE
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates in 2020, 2019, and 2018 respectively of:
•$1 million, $1 million, and $1 million at PECO
•$10 million, $18 million, and $21 million at BGE
(e)Includes late payment charge revenues.
During the first quarter of 2018, Mystic Unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation notified ISO-NE of the early retirement of its Mystic Generating Station's Units 7, 8, 9 and the Mystic Jet Unit (Mystic Generating Station assets) absent regulatory reforms. These events suggested that the carrying value of its New England asset group may be impaired. As a result, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and no impairment charge was required. Further developments such as the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in future impairments of the New England asset group, which could be material. See Note 8 — Early Plant Retirements for additional information.
In the third quarter of 2015, PHI entered into a sponsorship agreement with the District of Columbia for future sponsorship rights associated with public property within the District of Columbia and paid the District of Columbia $25 million, which Exelon and PHI had recorded as a finite-lived intangible asset as of December 31, 2016. The specific sponsorship rights were to be determined over time through future negotiations. In the fourth quarter of
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 6 — Accounts Receivable
2017, based upon6. Accounts Receivable (All Registrants)
Allowance for Credit Losses on Accounts Receivable (All Registrants)
The following table presents the lackrollforward of currently available sponsorship opportunities, the asset was written off and a pre-tax impairment charge of $25 million was recorded within Operating and maintenance expense in Exelon’s and PHI’s Consolidated Statements of Operations and Comprehensive Income.
On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate an orderly sales process to sell the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain of EGTP's assets and liabilities as heldAllowance for sale at their respective fair values less costs to sell and recorded a pre-tax impairment charge of $460 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income during 2017. On November 7, 2017, EGTP and its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy CourtCredit Losses on Customer Accounts Receivable for the District of Delaware and,year ended December 31, 2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of December 31, 2019 | $ | 243 | | | $ | 80 | | | $ | 59 | | | $ | 55 | | | $ | 12 | | | $ | 37 | | | $ | 13 | | | $ | 11 | | | $ | 13 | |
Plus: Current Period Provision for Expected Credit Losses(a) | 248 | | | 13 | | | 62 | | | 79 | | | 30 | | | 64 | | | 24 | | | 15 | | | 25 | |
Less: Write-offs, net of recoveries(b) | 69 | | | 5 | | | 24 | | | 18 | | | 7 | | | 15 | | | 5 | | | 4 | | | 6 | |
Less: Sale of customer accounts receivable(c) | 56 | | | 56 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance as of December 31, 2020 | $ | 366 | | | $ | 32 | | | $ | 97 | | | $ | 116 | | | $ | 35 | | | $ | 86 | | | $ | 32 | | | $ | 22 | | | $ | 32 | |
_________
(a)For the Utility Registrants, the increase is primarily as a result Exelonof increased aging of receivables, the temporary suspension of customer disconnections for non-payment, temporary cessation of new late payment fees, and Generation deconsolidated EGTP's assets and liabilities from their consolidated financial statements. reconnection of service to customers previously disconnected due to COVID-19.
(b)Recoveries were not material to the Registrants.
(c)See Note 5 — Mergers, Acquisitions and Dispositionsbelow for additional information.
Ininformation on the sale of customer accounts receivable at Generation in the second quarter of 2016, updates to Exelon's long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair value of the group were less than their carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result of the fair value analysis, long-lived merchant wind assets held and used with a carrying amount of approximately $60 million were written down to their fair value of $24 million and a pre-tax impairment charge of $36 million was recorded during the second quarter of 2016 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
In the first quarter of 2016, significant changes in Generation’s intended use of the Upstream oil and gas assets, developments with nonrecourse debt held by its Upstream subsidiary CEU Holdings, LLC (as described in Note 13 — Debt and Credit Agreements) and continued declines in both production volumes and commodity prices suggested that the carrying value may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of its Upstream properties were less than their carrying values. As a result, a pre-tax impairment charge of $119 million was recorded in March 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. On June 16, 2016, Generation initiated the sales process of its Upstream natural gas and oil exploration and production business by executing a forbearance agreement with the lenders of the nonrecourse debt, see Note 13 — Debt and Credit Agreements for additional information. An additional pre-tax impairment charge of $15 million was recorded in September 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income due to further declines in fair value. In December 2016, Generation sold substantially all of the Upstream Assets. See Note 5—Mergers, Acquisitions and Dispositions for additional information.2020.
The fair value analysis used infollowing table presents the above impairments was primarily basedrollforward of Allowance for Credit Losses on Other Accounts Receivable for the income approach using significant unobservable inputs (Level 3) including revenue, generation and production forecasts, projected capital and maintenance expenditures and discount rates. Changes in the assumptions described above could potentially result in future impairments of Exelon’s long-lived assets, which could be material.year ended December 31, 2020.
Like-Kind Exchange Transaction (Exelon) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of December 31, 2019 | $ | 48 | | | $ | 0 | | | $ | 20 | | | $ | 7 | | | $ | 5 | | | $ | 16 | | | $ | 7 | | | $ | 4 | | | $ | 5 | |
| Plus: Current Period Provision for Expected Credit Losses | 33 | | | 0 | | | 5 | | | 3 | | | 7 | | | 18 | | | 6 | | | 5 | | | 7 | |
Less: Write-offs, net of recoveries(a) | 10 | | | 0 | | | 4 | | | 2 | | | 3 | | | 1 | | | 0 | | | 0 | | | 1 | |
| Balance as of December 31, 2020 | $ | 71 | | | $ | 0 | | | $ | 21 | | | $ | 8 | | | $ | 9 | | | $ | 33 | | | $ | 13 | | | $ | 9 | | | $ | 11 | |
In June 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon Corporation, entered into transactions pursuant to which UII invested in coal-fired generating station leases (Headleases) with the Municipal Electric Authority of Georgia (MEAG). The generating stations_________
(a)Recoveries were leased back to MEAG as part of the transactions (Leases).
Pursuantnot material to the applicable authoritative guidance, Exelon is required to review the estimated residual valuesRegistrants.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 6 — Accounts Receivable
flows associatedUnbilled Customer Revenue (All Registrants)
The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of December 31, 2020 and 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unbilled customer revenues(a) |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| December 31, 2020 | $ | 998 | | | $ | 258 | | | $ | 218 | | | $ | 147 | | | $ | 197 | | | $ | 178 | | | $ | 87 | | | $ | 62 | | | $ | 29 | |
| December 31, 2019 | 1,535 | | | 807 | | | 218 | | | 146 | | | 170 | | | 194 | | | 100 | | | 61 | | | 33 | |
_________
(a)Unbilled customer revenues are classified in Customer accounts receivables, net in the Registrants' Consolidated Balance Sheets.
Sales of Customer Accounts Receivable (Exelon and Generation)
On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly-owned by Generation, entered into a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (the Purchasers) to sell certain customer accounts receivable (the Facility). The Facility, whose maximum capacity is $750 million, is scheduled to expire on April 7, 2021, unless renewed by the service contract option discussed above given that a market participant would take into consideration allmutual consent of the termsparties in accordance with its terms. Under the Facility, NER may sell eligible short-term customer accounts receivable to the Purchasers in exchange for cash and conditions containedsubordinated interest. The transfers are reported as sales of receivables in Exelon’s and Generation’s consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers is referred to as the DPP, which is reflected in Other current assets on Exelon’s and Generation’s Consolidated Balance Sheet.
On April 8, 2020, Generation derecognized and transferred approximately $1.2 billion of receivables at fair value to the Purchasers in exchange for approximately $500 million in cash purchase price and $650 million of DPP. On February 17, 2021, Generation received additional cash of $250 million from the Purchasers for the remaining capacity in the lease agreements.Facility.
AllThe following table summarizes the Headleases were terminated by the second quarter of 2016, and no events occurred prior to the termination that required Exelon to review the estimated residual valuesimpact of the direct financing lease investments in 2016. On March 31, 2016, UII and MEAG finalized an agreement to terminatesale of certain receivables:
| | | | | |
| As of December 31, 2020 |
Derecognized receivables transferred at fair value(a) | $ | 1,139 | |
| Cash proceeds received | 500 | |
| DPP | 639 | |
_________
(a)Includes additional customer accounts receivable sold into the MEAG Headleases,Facility of $6,608 million since the MEAG Leases, and other related agreements prior to their expiration dates. As a resultstart of the lease termination, UII received an early termination payment of $360 million from MEAG and wrote-off the $356 million net investment in the MEAG Headleases and the Leases. The transaction resulted in a pre-tax gain of $4 million which is reflectedfinancing agreement.
| | | | | |
| For the year ended December 31, 2020 |
Loss on sale of receivables(a) | $ | 30 | |
_________
(a)Reflected in Operating and maintenance expense in Exelon'son Exelon and Generation's Consolidated StatementsStatement of Operations and Comprehensive Income.
| | | | | |
| For the year ended December 31, 2020 |
| Proceeds from new transfers | $ | 2,816 | |
| Cash collections received on DPP | 3,771 | |
| Cash collections reinvested in the Facility | 6,587 | |
Generation’s risk of loss following the transfer of accounts receivable is limited to the DPP outstanding. Payment of DPP is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred, which have historically been and are expected to be immaterial. Generation continues to service the receivables sold in exchange for a servicing fee. Generation did not record a servicing asset or liability as the servicing fees were immaterial.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 6 — Accounts Receivable
Generation recognizes the cash proceeds received upon sale in Net cash provided by operating activities in the Consolidated Statement of Cash Flows. The collection and reinvestment of DPP is recognized in Net cash provided by investing activities of the Consolidated Statement of Cash Flows.
See Note 1418 — Income TaxesFair Value of Financial Assets and Liabilities and Note 23 — Variable Interest Entities for additional information.
Other Purchases and Sales of Customer and Other Accounts Receivables (All Registrants) 8.Generation is required, under supplier tariffs in ISO-NE, MISO, NYISO, and PJM, to sell customer and other receivables to utility companies, which include the Utility Registrants. The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. The following tables present the total receivables purchased and sold for the year ended December 31, 2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Total Receivables Purchased | $ | 3,529 | | | $ | 0 | | | $ | 1,094 | | | $ | 1,020 | | | $ | 652 | | | $ | 1,015 | | | $ | 622 | | | $ | 207 | | | $ | 186 | |
| Total Receivables Sold | 572 | | | 824 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Related Party Transactions: | | | | | | | | | | | | | | | | | |
| Receivables purchased from Generation | — | | | — | | | 34 | | | 67 | | | 79 | | | 72 | | | 51 | | | 13 | | | 8 | |
| Receivables sold to the Utility Registrants | — | | | 252 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
7. Early Plant Retirements (Exelon and Generation)
Exelon and Generation continuously evaluate factors that affect the current and expected economic value of Generation’s plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for the benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any plant, and the resulting financial statement impacts, may be affected by many factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, just prior to its next scheduled nuclear refueling outage.
Nuclear Generation
In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York, and Three Mile IslandTMI nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors.
On June 2, 2016, Generation announced it would shutdown the Clinton and Quad Cities nuclear plants on June 1, 2017 and June 1, 2018, respectively, given a lack of progress on Illinois energy legislation and MISO market reforms, and capacity auctions results that failed to cover cash operating costs and a risk-adjusted rate of return to shareholders.
On December 7, 2016, Illinois FEJA was signed into law by the Governor of Illinois and included a ZES that now provides compensation to Clinton and Quad Cities for the carbon-free attributes of their production through 2027. With the passage of the Illinois ZES in December 2016, Generation reversed its June 2016 decision to permanently cease generation operations at the Clinton and Quad Cities nuclear generating plants. Clinton and Quad Cities are currently licensed to operate through 2026 and 2032, respectively. See Note 4 - Regulatory Matters for additional information on the Illinois FEJA and the ZES.
In New York, the Ginna and Nine Mile Point nuclear plants faced similar economic challenges and on August 1, 2016, the NYPSC issued an order adopting the CES, which now provides payments to Ginna and Nine Mile Point, as well as FitzPatrick, for the environmental attributes of their production through 2029. Ginna and Nine Mile Point Unit 1 are currently licensed to operate through 2029, and Nine Mile Point Unit 2 through 2046. See Note 4 - Regulatory Matters for additional information on the New York CES.
Assuming the continued effectiveness of both the Illinois ZES and the New York CES, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to the extent either the Illinois ZES or the New York CES programs do not operate as expected over their full terms, each of these plants could again be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements.
In Pennsylvania, the TMI nuclear plant failed to clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear in the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019. TMI is currently committed to operate through May 2019 and is licensed to operate through 2034. Generation has filed the required market and regulatory notifications to shutdown the plant. PJM has subsequently notified Generation that it has not identified any reliability issues and has approved the deactivation of TMI as proposed.
In 2010, Generation announced that Oyster Creek would retire by the end of 2019 as part of an agreement with the State of New Jersey to avoid significant costs associated with the construction of cooling towers to meet the State's then new environmental regulations. Since then, like other nuclear sites, Oyster Creek continued to face rising operating costs amid a historically low wholesale power price environment. On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at the Oyster Creek nuclear plant at the end of its current operating cycle and permanently ceased generation operations in September 2018.
As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized one-time charges in Operating and maintenance expense related to materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments, among other items. In addition to these one-time charges, annual incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions were also recorded. See Note 15 — Asset Retirement Obligations for additional information on changes to the nuclear decommissioning ARO balance. The total annual impact of these charges by year are summarized in the table below.
|
| | | | | | | | | | | | |
| Income statement expense (pre-tax) | | 2018(a) | | 2017(b) | | 2016(c) |
| Depreciation and Amortization | | | | | | |
Accelerated depreciation(d) | | $ | 539 |
| | $ | 250 |
| | $ | 712 |
|
| Accelerated nuclear fuel amortization | | 57 |
| | 12 |
| | 60 |
|
| Operating and Maintenance | | | | | | |
One-time charges(e,f) | | 32 |
| | 77 |
| | 26 |
|
Change in ARO accretion, net of any contractual offset(g) | | — |
| | — |
| | 2 |
|
Contractual offset for ARC depreciation(g) | | — |
| | — |
| | (86 | ) |
| Total | | $ | 628 |
| | $ | 339 |
| | $ | 714 |
|
_________
| |
(a) | Reflects incremental accelerated depreciation for TMI and Oyster Creek. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018. |
| |
(b) | Reflects incremental charges for TMI including incremental accelerated depreciation and amortization from May 30, 2017 through December 31, 2017. |
| |
(c) | Reflects incremental charges for Clinton and Quad Cities including incremental accelerated depreciation and amortization from June 2, 2016 through December 6, 2016. In December 2016, as a result of reversing its retirement decision for Clinton and Quad Cities, Exelon and Generation updated the expected economic useful life for both facilities, to 2027 for Clinton, commensurate with the end of the Illinois ZES, and to 2032 for Quad Cities, the end of its current operating license. Depreciation was therefore adjusted beginning December 7, 2016, to reflect these extended useful life estimates. |
| |
(d) | Reflects incremental accelerated depreciation of plant assets, including any ARC. |
| |
(e) | Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments. Excludes the charge to Operating and maintenance expense from the ARO remeasurement due to the announced sale of Oyster Creek. See Note 5 — Mergers, Acquisitions and Dispositions for additional information. |
| |
(f) | In June 2016, as a result of the retirement decision for Clinton and Quad Cities, Exelon and Generation recognized one-time charges of $146 million. In December 2016, as a result of reversing its retirement decision for Clinton and Quad Cities, Exelon and Generation reversed approximately $120 million of these one-time charges initially recorded in June 2016. |
| |
(g) | For Quad Cities based on the regulatory agreement with the ICC, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision makingdecision-making authority to retire Salem.
On May 23, 2018, New Jersey enacted legislation that established a ZEC program, similar to that in Illinois and New York, that will provide compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. The NJBPU must complete its processes for determining eligibility for, and participation in, the ZEC program by April 18, 2019. On December 19, 2018, PSEG submitted its application for Salem. Assuming the successful implementationcontinued effectiveness of the Illinois ZES, New Jersey ZEC program, and the selectionNew York CES, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Salem, Ginna, or Nine Mile Point to be at heightened risk for early retirement. However, to the extent the Illinois ZES, New Jersey ZEC program, or the New York CES do not operate as oneexpected over their full terms,
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 7 — Early Plant Retirements
each of these plants, in addition to FitzPatrick, would be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements. In addition, FERC’s December 19, 2019 order on the MOPR in PJM may undermine the continued effectiveness of the qualifying facilities,Illinois ZES and the New Jersey ZEC program hasunless Illinois and New Jersey implement an FRR mechanism under which the potential to mitigate the heightened risk of earlier retirement for Salem.Generation plants in these states would be removed from PJM’s capacity auction. See Note 4 -3 — Regulatory Matters for additional information.information on the Illinois ZES, New Jersey ZEC program, New York CES, and FERC's December 19, 2019 order on the MOPR in PJM.
The following table providesIn Pennsylvania, the balance sheet amounts asTMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of December 31, 2018low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for Generation’s ownership share of the significant assets and liabilities associated with Salemits ability to produce electricity without air pollution, Generation announced that it would potentially be impacted by a decision to permanently cease generation operations.
|
| | | | |
| | | December 31, 2018 |
| Asset Balances | | |
| Materials and supplies inventory | | $ | 45 |
|
| Nuclear fuel inventory, net | | 118 |
|
| Completed plant, net | | 538 |
|
| Construction work in progress | | 44 |
|
| Liability Balances | | |
| Asset retirement obligation | | (395 | ) |
| | | |
| NRC License Renewal Term | | 2036 (unit 1) |
|
| | | 2040 (unit 2) |
|
Generation’s Dresden, Byron, and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. While all of LaSalle's capacity did clear in the 2021-2022 planning year auction, Generation has become increasingly concerned about the economic viability of this plant as well in a landscape where energy market prices remain depressed and energy market rules remain fatally flawed.
On August 27, 2020, Generation announced that it intends to permanently cease generation operations at Byron in September 2021 and at Dresden in November 2021. The current NRC licenses for Byron Units 1 and 2 expire in 2044 and 2046, respectively, and the licenses for Dresden Units 2 and 3 expire in 2029 and 2031, respectively.
As a result of the decision to early retire Byron and Dresden, Exelon and Generation recognized certain one-time charges for the year ended December 31, 2020 related to materials and supplies inventory reserve adjustments, employee-related costs, including severance benefit costs further discussed below, and construction work-in-progress impairments, among other items. In addition, as a result of the decisions to early retire Byron and Dresden, there are ongoing annual financial impacts stemming from shortening the expected economic useful lives of these nuclear plants primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and changes in ARO accretion expense associated with the changes in decommissioning timing and cost assumptions to reflect an earlier retirement date. See Note 10 — Asset Retirement Obligations for additional information on changes to the nuclear decommissioning ARO balance and Note 12 — Asset Impairments for impairment assessment considerations given to the Midwest asset group as a result of the early retirement decision. The total impact on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income is summarized in the table below.
| | | | | | | | | | | | | | | | | | | | |
| Income statement expense (pre-tax) | | 2020(a) | | 2019(b) | | 2018(c) |
| Depreciation and amortization | | | | | | |
Accelerated depreciation(d) | | $ | 895 | | | $ | 216 | | | $ | 539 | |
| Accelerated nuclear fuel amortization | | 60 | | | 13 | | | 57 | |
| Operating and maintenance | | | | | | |
| One-time charges | | 255 | | | 0 | | | 32 | |
Other charges(e) | | 34 | | | (53) | | | 0 | |
Contractual offset(f) | | (364) | | | 0 | | | 0 | |
| Total | | $ | 880 | | | $ | 176 | | | $ | 628 | |
| | | | | | |
_________
(a)Reflects expense for Byron and Dresden.
(b)Reflects expense for TMI.
(c)Reflects expense for TMI and Oyster Creek.
(d)Includes the accelerated depreciation of plant assets including any ARC.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 7 — Early Plant Retirements
(e)For Dresden, reflects the net impacts associated with the remeasurement of the ARO. For TMI, primarily reflects the net impacts associated with the remeasurement of the ARO. See Note 10 - Asset Retirement Obligations for additional information.
(f)Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of the ARO. For Byron and Dresden, based on the regulatory agreement with the ICC, decommissioning-related activities in 2020 have been offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset in 2020 resulted in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 10 - Asset Retirement Obligations for additional information.
Severance benefit costs will be provided to employees impacted by the early retirements of Byron and Dresden, to the extent they are not redeployed to other nuclear plants. For the year ended December 31, 2020, Exelon and Generation recorded severance expense of $81 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. The final amount of severance benefit costs will depend on the specific employees severed.
The following table provides the balance sheet amounts as of December 31, 2020 for Exelon's and Generation's significant assets and liabilities associated with the Braidwood and LaSalle nuclear plants. Current depreciation provisions are based on the estimated useful lives of these nuclear generating stations, which reflect the first renewal of the operating licenses.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Braidwood | | LaSalle | | Total |
| Asset Balances | | | | | | | | | | |
| Materials and supplies inventory, net | | | | | | $ | 84 | | | $ | 106 | | | $ | 190 | |
| Nuclear fuel inventory, net | | | | | | 120 | | | 285 | | | 405 | |
| Completed plant, net | | | | | | 1,397 | | | 1,590 | | | 2,987 | |
| Construction work in progress | | | | | | 31 | | | 30 | | | 61 | |
| Liability Balances | | | | | | | | | | |
| Asset retirement obligation | | | | | | (570) | | | (954) | | | (1,524) | |
| | | | | | | | | | |
| NRC License First Renewal Term | | | | | | 2046 (Unit 1) | | 2042 (Unit 1) | | |
| | | | | 2047 (Unit 2) | | 2043 (Unit 2) | | |
Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level. The absence of such solutions or reforms could result in future impairments of the Midwest asset group, or accelerated depreciation for specific plants over their shortened estimated useful lives, both of which could have a material unfavorable impact on Exelon's and Generation's future results of operations.
Other Generation
OnIn March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire, itsamong other assets, the Mystic Generating Station assetsStation's units 8 and 9 (Mystic 8 and 9) absent regulatory reforms onto properly value reliability and regional fuel security. Thereafter, ISO-NE identified Mystic 8 and 9 as being needed to ensure fuel security for the region and entered into a cost of service agreement with these two units for the period between June 1, 2022 at- May 31, 2024. The agreement was approved by the end of the current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 is currently committed through May 2021.FERC in December 2018.
The ISO-NE announced that it would takeOn June 10, 2020, Generation filed a three-step approach to fuel security.
First, on May 1, 2018, ISO-NE made a filingcomplaint with FERC requesting waiveragainst ISO-NE stating that ISO-NE failed to follow its tariff with respect to its evaluation of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fueltransmission security for the 2022 - 2024 capacityto 2025 Capacity Commitment Period (FCA 15) and that the modifications that ISO-NE made to its unfiled planning procedures to avoid retaining Mystic 8 and 9 should have been filed with FERC for approval. On August 17, 2020, FERC issued an order denying the complaint. As a result, on August 20, 2020, Exelon determined that Generation will permanently cease generation operations at Mystic 8 and 9 at the expiration of the cost of service commitment periods. FERC deniedin May 2024. See Note 3 — Regulatory Matters for additional discussion of Mystic’s cost of service agreement.
As a result of the waiver request on procedural grounds on July 2, 2018decision to early retire Mystic 8 and ordered ISO-NE to (i) make a filing within 60 days providing9, Exelon and Generation recognized $22 million of one-time charges for the filingyear ended December 31, 2020, related to materials and supplies inventory reserve adjustments, among other items. In addition, there are annual financial impacts stemming from shortening the expected economic useful life of a short-term cost-of-service agreementMystic 8 and 9 primarily related to address fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns.accelerated depreciation of plant assets.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 7 — Early Plant Retirements
Second, in accordance with FERC's July 2, 2018 order, on AugustExelon and Generation recorded incremental Depreciation and amortization expense of $26 million for the year ended December 31, 2018, ISO-NE made a filing with FERC proposing short-term tariff changes to permit it to retain a resource2020. See Note 12 — Asset Impairments for fuel security reliability reasons, which FERC accepted on December 3, 2018.
Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot recover future operating costs, including the cost of procuring fuel. In its July 2, 2018 order, FERC ordered ISO-NE to make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. In January 2019, ISO-NE has indicated that it intends to seek an extensionimpairment assessment considerations of the deadline for this filing to November 15, 2019.New England Asset Group.
On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation
8. Property, Plant, and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. Among the costs included in the filing are costs associated with the Everett Marine Terminal. On December 20, 2018, FERC issued an order accepting the cost of service agreement reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. FERC also directed a paper hearing on ROE using a new methodology. Initial and reply briefs on ROE will be due on April 18, 2019 and July 18, 2019. These will be reflected in a compliance filing due February 18, 2019. On January 4, 2019, Generation notified ISO-NE that it will participate in the Forward Capacity Market auction for the 2022 - 2023 capacity commitment period. In addition, on January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the December 20, 2018 order. The request for rehearing does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022-2023 capacity commitment period.Equipment (All Registrants)
The following table provides the balance sheet amountstables present a summary of property, plant, and equipment by asset category as of December 31, 2018 for Generation’s significant assets2020 and liabilities associated with2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Asset Category | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| December 31, 2020 | | | | | | | | | | | | | | | | | |
| Electric—transmission and distribution | $ | 60,946 | | | $ | 0 | | | $ | 29,371 | | | $ | 9,462 | | | $ | 8,797 | | | $ | 15,137 | | | $ | 10,264 | | | $ | 4,730 | | | $ | 4,568 | |
| Electric—generation | 29,725 | | | 29,724 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Gas—transportation and distribution | 6,733 | | | 0 | | | 0 | | | 3,098 | | | 3,315 | | | 591 | | | 0 | | | 751 | | | 0 | |
| Common—electric and gas | 2,170 | | | 0 | | | 0 | | | 956 | | | 1,138 | | | 178 | | | 0 | | | 180 | | | 0 | |
Nuclear fuel(a) | 5,399 | | | 5,399 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Construction work in progress | 3,576 | | | 450 | | | 799 | | | 474 | | | 627 | | | 1,174 | | | 824 | | | 163 | | | 182 | |
Other property, plant, and equipment(b) | 762 | | | 11 | | | 59 | | | 34 | | | 29 | | | 108 | | | 65 | | | 23 | | | 28 | |
| Total property, plant, and equipment | 109,311 | | | 35,584 | | | 30,229 | | | 14,024 | | | 13,906 | | | 17,188 | | | 11,153 | | | 5,847 | | | 4,778 | |
Less: accumulated depreciation(c) | 26,727 | | | 13,370 | | | 5,672 | | | 3,843 | | | 4,034 | | | 1,811 | | | 3,697 | | | 1,533 | | | 1,303 | |
| Property, plant, and equipment, net | $ | 82,584 | | | $ | 22,214 | | | $ | 24,557 | | | $ | 10,181 | | | $ | 9,872 | | | $ | 15,377 | | | $ | 7,456 | | | $ | 4,314 | | | $ | 3,475 | |
| | | | | | | | | | | | | | | | | |
| December 31, 2019 | | | | | | | | | | | | | | | | | |
| Electric—transmission and distribution | $ | 56,809 | | | $ | 0 | | | $ | 27,566 | | | $ | 8,957 | | | $ | 8,326 | | | $ | 13,809 | | | $ | 9,734 | | | $ | 4,464 | | | $ | 4,207 | |
| Electric—generation | 29,839 | | | 29,839 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Gas—transportation and distribution | 6,147 | | | 0 | | | 0 | | | 2,899 | | | 2,999 | | | 525 | | | 0 | | | 690 | | | 0 | |
| Common—electric and gas | 1,907 | | | 0 | | | 0 | | | 877 | | | 991 | | | 146 | | | 0 | | | 160 | | | 0 | |
Nuclear fuel(a) | 5,656 | | | 5,656 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Construction work in progress | 3,055 | | | 702 | | | 662 | | | 250 | | | 483 | | | 921 | | | 628 | | | 125 | | | 166 | |
Other property, plant and equipment(b) | 799 | | | 13 | | | 47 | | | 27 | | | 25 | | | 108 | | | 64 | | | 21 | | | 27 | |
| Total property, plant and equipment | 104,212 | | | 36,210 | | | 28,275 | | | 13,010 | | | 12,824 | | | 15,509 | | | 10,426 | | | 5,460 | | | 4,400 | |
Less: accumulated depreciation(c) | 23,979 | | | 12,017 | | | 5,168 | | | 3,718 | | | 3,834 | | | 1,213 | | | 3,517 | | | 1,425 | | | 1,210 | |
| Property, plant, and equipment, net | $ | 80,233 | | | $ | 24,193 | | | $ | 23,107 | | | $ | 9,292 | | | $ | 8,990 | | | $ | 14,296 | | | $ | 6,909 | | | $ | 4,035 | | | $ | 3,190 | |
__________
(a)Includes nuclear fuel that is in the Mystic Units 8fabrication and 9installation phase of $939 million and Everett Marine Terminal assets that would potentially be impacted by a decision to permanently cease generation operations.$1,025 million at December 31, 2020 and 2019, respectively.
(b)Primarily composed of land and non-utility property.
(c)Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,774 million and $2,867 million as of December 31, 2020 and 2019, respectively.
|
| | | | |
| | | December 31, 2018 |
| Asset Balances | | |
| Materials and supplies inventory | | $ | 30 |
|
| Fuel inventory | | 20 |
|
| Completed plant, net | | 901 |
|
| Construction work in progress | | 9 |
|
| Liability Balances | | |
| Asset retirement obligation | | (1 | ) |
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 8 — Property, Plant, and Equipment
The following table presents the average service life for each asset category in number of years:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Average Service Life (years) |
| Asset Category | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Electric - transmission and distribution | 5-80 | | N/A | | 5-80 | | 5-70 | | 5-80 | | 5-75 | | 5-75 | | 5-70 | | 5-65 |
| Electric - generation | 1-58 | | 1-58 | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A |
| Gas - transportation and distribution | 5-80 | | N/A | | N/A | | 5-70 | | 5-80 | | 5-75 | | N/A | | 5-75 | | N/A |
| Common - electric and gas | 4-75 | | N/A | | N/A | | 5-55 | | 4-50 | | 5-75 | | N/A | | 5-75 | | N/A |
| Nuclear fuel | 1-8 | | 1-8 | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A |
| Other property, plant, and equipment | 1-50 | | 1-10 | | 33-50 | | 50 | | 20-50 | | 3-50 | | 25-50 | | 8-50 | | 13-15 |
Depreciation provisions are based on the estimated useful lives of the stations, which reflect the first renewal of the operating licenses for all of Generation's operating nuclear generating stations except for Clinton, Byron, Dresden, and Peach Bottom. Clinton depreciation provisions are based on an estimated useful life through 2027, which is the last year of the Illinois ZES. Peach Bottom depreciation provisions are based on estimated useful life of 2053 and 2054 for Unit 2 and Unit 3, respectively, which reflects the second renewal of its operating licenses. Beginning August 2020, Byron, Dresden, and Mystic depreciation provisions were based on their announced shutdown dates of September 2021, November 2021, and May 2024, respectively. See Note 3 — Regulatory Matters for additional information regarding license renewals and the Illinois ZECs and Note 7 — Early Plant Retirements for additional information on the impacts of early plant retirements.
The following table presents the annual depreciation rates for each asset category. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method and not included in the below table.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Annual Depreciation Rates |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| December 31, 2020 | | | | | | | | | | | | | | | | | |
| Electric—transmission and distribution | 2.79 | % | | N/A | | 2.95 | % | | 2.31 | % | | 2.69 | % | | 2.81 | % | | 2.53 | % | | 2.85 | % | | 3.08 | % |
| Electric—generation | 6.11 | % | | 6.11 | % | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A |
| Gas—transportation and distribution | 2.14 | % | | N/A | | N/A | | 1.85 | % | | 2.56 | % | | 1.50 | % | | N/A | | 1.50 | % | | N/A |
| Common—electric and gas | 7.01 | % | | N/A | | N/A | | 6.39 | % | | 7.45 | % | | 7.36 | % | | N/A | | 6.72 | % | | N/A |
| | | | | | | | | | | | | | | | | |
| December 31, 2019 | | | | | | | | | | | | | | | | | |
| Electric—transmission and distribution | 2.80 | % | | N/A | | 2.99 | % | | 2.36 | % | | 2.60 | % | | 2.77 | % | | 2.47 | % | | 2.86 | % | | 2.94 | % |
| Electric—generation | 4.35 | % | | 4.35 | % | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A |
| Gas—transportation and distribution | 2.04 | % | | N/A | | N/A | | 1.89 | % | | 2.30 | % | | 1.55 | % | | N/A | | 1.55 | % | | N/A |
| Common—electric and gas | 7.37 | % | | N/A | | N/A | | 6.06 | % | | 8.30 | % | | 8.25 | % | | N/A | | 6.24 | % | | N/A |
| | | | | | | | | | | | | | | | | |
| December 31, 2018 | | | | | | | | | | | | | | | | | |
| Electric—transmission and distribution | 2.73 | % | | N/A | | 2.95 | % | | 2.35 | % | | 2.61 | % | | 2.61 | % | | 2.40 | % | | 2.77 | % | | 2.45 | % |
| Electric—generation | 5.37 | % | | 5.37 | % | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A | | N/A |
| Gas—transportation and distribution | 2.07 | % | | N/A | | N/A | | 1.90 | % | | 2.36 | % | | 1.59 | % | | N/A | | 1.59 | % | | N/A |
| Common—electric and gas | 6.98 | % | | N/A | | N/A | | 5.44 | % | | 8.50 | % | | 6.30 | % | | N/A | | 3.70 | % | | N/A |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 8 — Property, Plant, and Equipment
Capitalized Interest and AFUDC (All Registrants)
The following table summarizes capitalized interest and credits to AFUDC by year:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| December 31, 2020 | | | | | | | | | | | | | | | | | |
| Capitalized interest | $ | 22 | | | $ | 22 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| AFUDC debt and equity | 150 | | | 0 | | | 42 | | | 23 | | | 30 | | | 55 | | | 42 | | | 6 | | | 7 | |
| | | | | | | | | | | | | | | | | |
| December 31, 2019 | | | | | | | | | | | | | | | | | |
| Capitalized interest | $ | 24 | | | $ | 24 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| AFUDC debt and equity | 132 | | | 0 | | | 32 | | | 17 | | | 29 | | | 54 | | | 39 | | | 6 | | | 9 | |
| | | | | | | | | | | | | | | | | |
| December 31, 2018 | | | | | | | | | | | | | | | | | |
| Capitalized interest | $ | 31 | | | $ | 31 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| AFUDC debt and equity | 109 | | | 0 | | | 30 | | | 12 | | | 24 | | | 44 | | | 34 | | | 4 | | | 4 | |
See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 17 — Debt and Credit Agreements for additional information regarding Exelon’s, ComEd’s, PECO's, Pepco's, DPL's, and ACE’s property, plant and equipment subject to mortgage liens.
9. Jointly Owned Electric Utility Plant (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL, and ACE)
Exelon's, Generation's, PECO's, BGE's, Pepco's, DPL's, and ACE's material undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 20182020 and 20172019 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nuclear Generation | | Fossil-Fuel Generation | | Transmission | | Other |
| | Quad Cities | | Peach Bottom | | Salem(a) | | Nine Mile Point Unit 2 | | Wyman | | PA(b) | | NJ/ DE(c) | | Other(d) |
| Operator | Generation | | Generation | | PSEG
Nuclear | | Generation | | FP&L | | First
Energy | | PSEG/ DPL | | various |
| Ownership interest | 75.00 | % | | 50.00 | % | | 42.59 | % | | 82.00 | % | | 5.89 | % | | various |
| | various |
| | various |
|
| Exelon’s share at December 31, 2018: | | | | | | | | | | | | | | | |
Plant(e) | $ | 1,131 |
| | $ | 1,451 |
| | $ | 648 |
| | $ | 910 |
| | $ | 4 |
| | $ | 28 |
| | $ | 103 |
| | $ | 15 |
|
Accumulated depreciation(e) | 587 |
| | 523 |
| | 227 |
| | 126 |
| | 3 |
| | 16 |
| | 53 |
| | 13 |
|
| Construction work in progress | 13 |
| | 15 |
| | 44 |
| | 56 |
| | — |
| | 1 |
| | — |
| | — |
|
| Exelon’s share at December 31, 2017: | | | | | | | | | | | | | | | |
Plant(e) | $ | 1,074 |
| | $ | 1,417 |
| | $ | 631 |
| | $ | 839 |
| | $ | 3 |
| | $ | 27 |
| | $ | 102 |
| | $ | 15 |
|
Accumulated depreciation(e) | 550 |
| | 461 |
| | 205 |
| | 97 |
| | 3 |
| | 15 |
| | 52 |
| | 13 |
|
| Construction work in progress | 35 |
| | 18 |
| | 33 |
| | 55 |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear Generation | | Transmission |
| Quad Cities | | Peach
Bottom | | Salem | | Nine Mile Point Unit 2 | | NJ/DE(a) |
| Operator | Generation | | Generation | | PSEG
Nuclear | | Generation | | PSEG/DPL |
| Ownership interest | 75.00 | % | | 50.00 | % | | 42.59 | % | | 82.00 | % | | various |
| Exelon’s share at December 31, 2020: | | | | | | | | | |
| Plant in service | $ | 1,188 | | | $ | 1,506 | | | $ | 717 | | | $ | 990 | | | $ | 103 | |
| Accumulated depreciation | 670 | | | 601 | | | 265 | | | 187 | | | 54 | |
| Construction work in progress | 13 | | | 13 | | | 39 | | | 25 | | | 0 | |
| Exelon’s share at December 31, 2019: | | | | | | | | | |
| Plant in service | $ | 1,161 | | | $ | 1,466 | | | $ | 663 | | | $ | 951 | | | $ | 102 | |
| Accumulated depreciation | 627 | | | 571 | | | 249 | | | 156 | | | 53 | |
| Construction work in progress | 13 | | | 21 | | | 53 | | | 27 | | | 0 | |
__________
| |
(a) | Generation also owns a proportionate share in the fossil-fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2018 and 2017. |
| |
(b) | PECO, BGE, Pepco, DPL and ACE own a 22%, 7%, 27%, 9% and 8% share, respectively, in 127 miles of 500kV lines located in Pennsylvania as well as a 20.72%, 10.56%, 9.72%, 3.72% and 3.83% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil-generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above. |
| |
(c) | PECO, DPL and ACE own a 42.55%, 1% and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and of the Salem generating plant substation. PECO, DPL and ACE also own a 42.55%, 7.45% and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching substation. |
| |
(d) | Generation, DPL and ACE own a 44.24%, 11.91% and 4.83% share, respectively in assets located at Merrill Creek Reservoir located in New Jersey. Pepco, DPL and ACE own a 11.9%, 7.4% and 6.6% share, respectively, in Valley Forge Corporate Center. |
| |
(e) | Excludes asset retirement costs and general plant. |
(a)PECO, DPL, and ACE own a 42.55%, 1%, and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and of the Salem generating plant substation. PECO, DPL, and ACE also own a 42.55%, 7.45%, and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching substation.
Exelon’s, Generation’s, PECO's, BGE's, Pepco's, DPL's, and ACE's undivided ownership interests are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. Exelon’s, Generation’s, PECO's, BGE's, Pepco's, DPL's, and ACE's share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and in Operating and maintenance expenses in PECO's, BGE's, Pepco's,PHI's, DPL's, and ACE's Consolidated Statements of Operations and Comprehensive Income.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
10. Asset Retirement Obligations (All Registrants)
Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Generation updates its ARO annually unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. Generation began decommissioning the TMI nuclear plant upon permanently ceasing operations in 2019. See below section for decommissioning of Zion Station.
The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC within Property, plant, and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2019 to December 31, 2020:
| | | | | |
| Nuclear decommissioning ARO at January 1, 2019 | $ | 10,005 | |
| Net increase due to changes in, and timing of, estimated future cash flows | 864 | |
| Sale of Oyster Creek | (755) | |
| Accretion expense | 479 | |
| Costs incurred related to decommissioning plants | (89) | |
Nuclear decommissioning ARO at December 31, 2019(a) | 10,504 | |
| Net increase due to changes in, and timing of, estimated future cash flows | 1,022 | |
| Accretion Expense | 489 | |
| Costs incurred related to decommissioning plants | (93) | |
Nuclear decommissioning ARO at December 31, 2020(a) | $ | 11,922 | |
| |
__________
(a)Includes $80 million and $112 million as the current portion of the ARO at December 31, 2020 and 2019, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.
The net $1,022 million increase in the ARO during 2020 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year. These adjustments primarily include:
•A net increase of approximately $800 million was driven by updates to Byron and Dresden reflecting changes in assumed retirement dates and assumed methods of decommissioning as a result of the announcement to early retire these plants in 2021. Refer to Note 7 — Early Plant Retirements for additional information.
•An increase of approximately $360 million resulting from the change in the assumed DOE spent fuel acceptance date for disposal from 2030 to 2035.
•A decrease of approximately $220 million due to lower estimated decommissioning costs primarily for Limerick and Peach Bottom nuclear units resulting from the completion of updated cost studies.
The 2020 ARO updates resulted in a increase of $60 million in Operating and maintenance expense for the year ended December 31, 2020 within Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
The net $864 million increase in the ARO during 2019 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments primarily include:
•An increase of approximately $780 million for changes in the assumed retirement timing probabilities for sites including certain economically challenged nuclear plants and the extension of Peach Bottom’s operating life.
•An increase of approximately $490 million for other impacts that included updated cost escalation rates, primarily for labor, equipment and materials, and current discount rates.
•Lower estimated costs to decommission TMI, Nine Mile Point, Ginna, Braidwood, Byron, and LaSalle nuclear units of approximately $410 million resulting from the completion of updated cost studies.
The 2019 ARO updates resulted in a decrease of $150 million in Operating and maintenance expense for the year ended December 31, 2019 within Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 7 — Early Plant Retirements for additional information regarding TMI and economically challenged nuclear plants and Note 3 — Regulatory Matters regarding the Peach Bottom second license renewal.
NDT Funds
NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.
The NDT funds associated with Generation's nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a decrease from the previously approved annual collection of approximately $24 million primarily due to the removal of the collections for Limerick Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the new rates became effective January 1, 2018.
Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party (see Zion Station Decommissioning below) and the CENG units, where any shortfall is required to be funded by both Generation and EDF. Generation, through PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from utility customers for any of Generation's other nuclear units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to NDT funds that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management and decommissioning) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities.
At December 31, 2020 and 2019, Exelon and Generation had NDT funds totaling $14,599 millionand $13,353 million, respectively. The NDT funds include $134 million and $163 million for the current portion of the NDT at December 31, 2020 and 2019, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 24 — Supplemental Financial Information for additional information on activities of the NDT funds.
Accounting Implications of the Regulatory Agreements with ComEd and PECO
Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are recorded by Generation and the corresponding regulated utility as a component of the intercompany and regulatory balances on the balance sheet. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.
For the former PECO units, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from PECO customers in the event of a shortfall and the obligation for Generation to ultimately return any excess funds to PECO customers (on an aggregate basis for all seven units),decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables or noncurrent receivables to affiliates at Generation with PECO recording an equal noncurrent affiliate receivable from or payable to Generation and a corresponding regulatory liability or regulatory asset. Any changes to the existing PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s financial statements could be material.
For the former ComEd units, given no further recovery from ComEd customers is permitted and Generation retains an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, the offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results with Generation recognizing an intercompany payable to ComEd while ComEd records an intercompany receivable from Generation with a corresponding regulatory liability.However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible and accounting for decommissioning-related activities at Generation for that unit would not be offset, and the impact to Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income could be material during such periods.
As of December 31, 2020, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are currently offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
See Note 3 — Regulatory Matters and Note 25 — Related Party Transactions for additional information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd, and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.
Zion Station Decommissioning
In 2010, Generation completed an ASA under which ZionSolutions assumed responsibility for decommissioning Zion Station and Generation transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds.
Following ZionSolutions' completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility.
Generation had retained its obligation for the SNF as well as certain NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. As of December 31, 2020, the ARO associated with Zion's SNF storage facility is $175 million and the NDT funds available to fund this obligation are $66 million.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the NRC methodology differ from the ARO recorded in Generation’s and Exelon’s Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees.
Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2020 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).
In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 2020 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain LLRW); (3) the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 4% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.6% to 6.1% (as compared to a historical 5-year annual average pre-tax return of approximately 9.0%).
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial positions may be significantly adversely affected.
Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 for all units, including its shutdown units, except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the April 1, 2019 submittal. On March 31, 2020, Generation filed its annual decommissioning funding status report with the NRC for Generation’s shutdown units (excluding Zion Station for the reason noted above). The annual status report demonstrated adequate decommissioning funding assurance as of December 31, 2019, for all of its shutdown reactors except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO ratepayers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff.
Generation will file its next decommissioning funding status report with the NRC by March 31, 2021. This report will reflect the status of decommissioning funding assurance as of December 31, 2020 and will include the 2021 early retirements of Byron and Dresden. A shortfall could require Exelon to post parental guarantee for Generation’s share of the funding assurance. However, the amount of any required guarantee will ultimately depend on the decommissioning approach adopted at Byron and Dresden, the associated level of costs, and the decommissioning trust fund investment performance going forward.
As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.
Non-Nuclear Asset Retirement Obligations (All Registrants)
Generation has AROs for plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations and other decommissioning-related activities. The Utility Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 — Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
The following table provides a rollforward of the non-nuclear AROs reflected in the Registrants’ Consolidated Balance Sheets from January 1, 2019 to December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Non-nuclear AROs at January 1, 2019 | $ | 471 | | | $ | 238 | | | $ | 121 | | | $ | 28 | | | $ | 25 | | | $ | 52 | | | $ | 37 | | | $ | 11 | | | $ | 4 | |
| Net increase (decrease) due to changes in, and timing of, estimated future cash flows | 17 | | | 7 | | | 8 | | | 0 | | | (2) | | | 4 | | | 3 | | | 1 | | | 0 | |
| Development projects | 2 | | | 2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Accretion expense(a) | 16 | | | 12 | | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | | 0 | | | 0 | |
| Asset divestitures | (42) | | | (42) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Payments | (4) | | | (1) | | | (1) | | | (1) | | | (1) | | | 0 | | | 0 | | | 0 | | | 0 | |
| Non-nuclear AROs at December 31, 2019 | 460 | | | 216 | | | 129 | | | 28 | | | 23 | | | 57 | | | 41 | | | 12 | | | 4 | |
| Net increase (decrease) due to changes in, and timing of, estimated future cash flows | 7 | | | 2 | | | 0 | | | 2 | | | 1 | | | 1 | | | (3) | | | 2 | | | 2 | |
| Development projects | 1 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Accretion expense(a) | 16 | | | 11 | | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | | 0 | | | 0 | |
| Asset divestitures | (4) | | | (4) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Payments | (9) | | | (4) | | | (1) | | | (2) | | | (2) | | | 0 | | | 0 | | | 0 | | | 0 | |
AROs reclassified to liabilities held for sale(b) | (10) | | | (10) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Non-nuclear AROs at December 31, 2020 | $ | 461 | | | $ | 212 | | | $ | 129 | | | $ | 29 | | | $ | 23 | | | $ | 59 | | | $ | 39 | | | $ | 14 | | | $ | 6 | |
__________
(a)For ComEd, PECO, BGE, PHI, Pepco, and DPL, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
(b)Represents AROs related to Generation's solar business, which were classified as held for sale as a result of the sale agreement. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.
11. Leases(All Registrants)
Lessee
The Registrants have operating and finance leases for which they are the lessees. The following tables outline the significant types of leases at each registrant and other terms and conditions of the lease agreements as of December 31, 2020. Exelon, Generation, ComEd, PECO, and BGE did not have material finance leases in 2020 or in 2019. PHI, Pepco, DPL, and ACE also did not have material finance leases in 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Contracted generation | ● | | ● | | | | | | | | | | | | | | |
| Real estate | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● |
| Vehicles and equipment | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in years) | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Remaining lease terms | 1-85 | | 1-35 | | 1-4 | | 1-13 | | 1-85 | | 1-11 | | 1-11 | | 1-11 | | 1-7 |
| Options to extend the term | 2-30 | | 2-30 | | 5 | | N/A | | N/A | | 3-30 | | 5 | | 3-30 | | 5 |
| Options to terminate within | 1-12 | | 1-4 | | 2 | | N/A | | 1 | | N/A | | N/A | | N/A | | N/A |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
The components of operating lease costs were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | |
| Operating lease costs | $ | 292 | | | $ | 194 | | | $ | 3 | | | $ | 1 | | | $ | 33 | | | $ | 46 | | | $ | 11 | | | $ | 13 | | | $ | 6 | |
| Variable lease costs | 241 | | | 234 | | | 1 | | | 0 | | | 1 | | | 2 | | | 1 | | | 1 | | | 0 | |
| Short-term lease costs | 2 | | | 2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Total lease costs (a) | $ | 535 | | | $ | 430 | | | $ | 4 | | | $ | 1 | | | $ | 34 | | | $ | 48 | | | $ | 12 | | | $ | 14 | | | $ | 6 | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | |
| Operating lease costs | $ | 320 | | | $ | 222 | | | $ | 3 | | | $ | 1 | | | $ | 33 | | | $ | 48 | | | $ | 12 | | | $ | 14 | | | $ | 7 | |
| Variable lease costs | 300 | | | 282 | | | 2 | | | 0 | | | 2 | | | 6 | | | 2 | | | 2 | | | 1 | |
| Short-term lease costs | 19 | | | 19 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Total lease costs (a) | $ | 639 | | | $ | 523 | | | $ | 5 | | | $ | 1 | | | $ | 35 | | | $ | 54 | | | $ | 14 | | | $ | 16 | | | $ | 8 | |
__________
(a)Excludes $48 million, $44 million, $4 million, and $4 million of sublease income recorded at Exelon, Generation, PHI, and DPL, respectively, for the year ended December 31, 2020 and $51 million, $44 million, $7 million, and $7 million of sublease income recorded at Exelon, Generation, PHI, and DPL, respectively, for the year ended December 31, 2019.
PHI, Pepco, DPL, and ACE recorded finance lease costs of $9 million, $3 million, $4 million, and $2 million, respectively, for the year ended December 31, 2020.
The following table presents the Registrants' rental expense under the prior lease accounting guidance for the year ended December 31, 2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rent expense | $ | 670 | | | $ | 558 | | | $ | 7 | | | $ | 10 | | | $ | 35 | | | $ | 48 | | | $ | 10 | | | $ | 13 | | | $ | 8 | |
| | | | | | | | | | | | | | | | | |
__________
(a)Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments table. Payments made under Generation's contracted generation lease agreements totaled $493 million.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
The following tables provide additional information regarding the presentation of operating and finance lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance Sheets:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Exelon(a) | | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | | | | | | | | | | | | | | | | | |
| Operating lease ROU assets | | | | | | | | | | | | | | | | | |
| Other deferred debits and other assets | $ | 1,064 | | | $ | 726 | | | $ | 7 | | | $ | 1 | | | $ | 46 | | | $ | 241 | | | $ | 49 | | | $ | 54 | | | $ | 15 | |
| | | | | | | | | | | | | | | | | |
| Operating lease liabilities | | | | | | | | | | | | | | | | | |
| Other current liabilities | 213 | | | 132 | | | 3 | | | 0 | | | 45 | | | 31 | | | 6 | | | 9 | | | 4 | |
| Other deferred credits and other liabilities | 1,089 | | | 775 | | | 5 | | | 1 | | | 19 | | | 224 | | | 46 | | | 56 | | | 11 | |
| Total operating lease liabilities | $ | 1,302 | | | $ | 907 | | | $ | 8 | | | $ | 1 | | | $ | 64 | | | $ | 255 | | | $ | 52 | | | $ | 65 | | | $ | 15 | |
| | | | | | | | | | | | | | | | | |
| As of December 31, 2019 | | | | | | | | | | | | | | | | | |
| Operating lease ROU assets | | | | | | | | | | | | | | | | | |
| Other deferred debits and other assets | $ | 1,305 | | | $ | 895 | | | $ | 9 | | | $ | 2 | | | $ | 77 | | | $ | 273 | | | $ | 56 | | | $ | 63 | | | $ | 18 | |
| | | | | | | | | | | | | | | | | |
| Operating lease liabilities | | | | | | | | | | | | | | | | | |
| Other current liabilities | 225 | | | 157 | | | 3 | | | 0 | | | 32 | | | 31 | | | 6 | | | 9 | | | 4 | |
| Other deferred credits and other liabilities | 1,307 | | | 925 | | | 8 | | | 1 | | | 50 | | | 254 | | | 51 | | | 65 | | | 14 | |
| Total operating lease liabilities | $ | 1,532 | | | $ | 1,082 | | | $ | 11 | | | $ | 1 | | | $ | 82 | | | $ | 285 | | | $ | 57 | | | $ | 74 | | | $ | 18 | |
__________
(a)Exelon's and Generation's operating ROU assets and lease liabilities include $387 million and $528 million, respectively, related to contracted generation as of December 31, 2020, and $515 million and $664 million, respectively, as of December 31, 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | | | | | | | | | | | | | | | | | |
| Finance lease ROU assets | | | | | | | | | | | | | | | | | |
| Plant, property and equipment, net | | | | | | | | | | | $ | 50 | | | $ | 17 | | | $ | 20 | | | $ | 13 | |
| | | | | | | | | | | | | | | | | |
| Finance lease liabilities | | | | | | | | | | | | | | | | | |
| Long-term debt due within one year | | | | | | | | | | | 7 | | | 2 | | | 3 | | | 2 | |
| Long-term debt | | | | | | | | | | | 43 | | | 15 | | | 17 | | | 11 | |
| Total finance lease liabilities | | | | | | | | | | | $ | 50 | | | $ | 17 | | | $ | 20 | | | $ | 13 | |
The weighted average remaining lease terms, in years, for operating and finance leases were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | 10.1 | | 10.5 | | 3.8 | | 4.2 | | 8.3 | | 8.2 | | 9.1 | | 9.1 | | 4.0 |
| As of December 31, 2019 | 10.1 | | 10.6 | | 4.6 | | 4.4 | | 5.4 | | 9.0 | | 9.8 | | 9.7 | | 4.7 |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | | | | | | | | | | | 6.5 | | 6.3 | | 6.5 | | 6.5 |
| | | | | | | | | | | | | | | | | |
The weighted average discount rates for operating and finance leases were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | 4.7 | % | | 4.9 | % | | 3.0 | % | | 2.9 | % | | 3.8 | % | | 4.2 | % | | 4.0 | % | | 4.0 | % | | 3.5 | % |
| As of December 31, 2019 | 4.6 | % | | 4.8 | % | | 3.0 | % | | 3.2 | % | | 3.6 | % | | 4.2 | % | | 4.0 | % | | 4.0 | % | | 3.6 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | | | | | | | | | | | 2.5 | % | | 2.6 | % | | 2.4 | % | | 2.4 | % |
| | | | | | | | | | | | | | | | | |
Future minimum lease payments for operating and finance leases as of December 31, 2020 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2021 | $ | 239 | | | $ | 145 | | | $ | 3 | | | $ | 1 | | | $ | 46 | | | $ | 40 | | | $ | 8 | | | $ | 11 | | | $ | 5 | |
| 2022 | 177 | | | 113 | | | 2 | | | 0 | | | 16 | | | 39 | | | 8 | | | 10 | | | 4 | |
| 2023 | 146 | | | 100 | | | 1 | | | 0 | | | 1 | | | 38 | | | 7 | | | 9 | | | 3 | |
| 2024 | 141 | | | 98 | | | 1 | | | 0 | | | 0 | | | 36 | | | 6 | | | 8 | | | 2 | |
| 2025 | 140 | | | 99 | | | 1 | | | 0 | | | 0 | | | 33 | | | 6 | | | 7 | | | 2 | |
| Remaining years | 834 | | | 640 | | | 0 | | | 0 | | | 18 | | | 120 | | | 28 | | | 35 | | | 0 | |
| Total | 1,677 | | | 1,195 | | | 8 | | | 1 | | | 81 | | | 306 | | | 63 | | | 80 | | | 16 | |
| Interest | 375 | | | 288 | | | 0 | | | 0 | | | 17 | | | 51 | | | 11 | | | 15 | | | 1 | |
| Total operating lease liabilities | $ | 1,302 | | | $ | 907 | | | $ | 8 | | | $ | 1 | | | $ | 64 | | | $ | 255 | | | $ | 52 | | | $ | 65 | | | $ | 15 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| Year | | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| 2021 | | | | | | | | | | | $ | 8 | | | $ | 3 | | | $ | 3 | | | $ | 2 | |
| 2022 | | | | | | | | | | | 8 | | | 3 | | | 3 | | | 2 | |
| 2023 | | | | | | | | | | | 8 | | | 3 | | | 3 | | | 2 | |
| 2024 | | | | | | | | | | | 8 | | | 3 | | | 3 | | | 2 | |
| 2025 | | | | | | | | | | | 8 | | | 3 | | | 3 | | | 2 | |
| Remaining years | | | | | | | | | | | 13 | | | 3 | | | 6 | | | 4 | |
| Total | | | | | | | | | | | 53 | | | 18 | | | 21 | | | 14 | |
| Interest | | | | | | | | | | | 3 | | | 1 | | | 1 | | | 1 | |
| Total finance lease liabilities | | | | | | | | | | | $ | 50 | | | $ | 17 | | | $ | 20 | | | $ | 13 | |
Cash paid for amounts included in the measurement of operating and finance lease liabilities were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating cash flows from operating leases |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | $ | 271 | | | $ | 204 | | | $ | 3 | | | $ | 1 | | | $ | 20 | | | $ | 39 | | | $ | 8 | | | $ | 9 | | | $ | 4 | |
| For the year ended December 31, 2019 | 287 | | | 206 | | | 3 | | | 0 | | | 33 | | | 37 | | | 9 | | | 6 | | | 5 | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Financing cash flows from finance leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2020 | | | | | | | | | | | $ | 6 | | | $ | 2 | | | $ | 3 | | | $ | 1 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
ROU assets obtained in exchange for operating and finance lease obligations were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | $ | 1 | | | $ | 3 | | | $ | 0 | | | $ | 1 | | | $ | 0 | | | $ | (1) | | | $ | 0 | | | $ | (1) | | | $ | 0 | |
| For the year ended December 31, 2019 | 52 | | | 14 | | | 6 | | | 0 | | | 2 | | | (3) | | | (1) | | | (2) | | | (1) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | $ | 29 | | | $ | 8 | | | $ | 14 | | | $ | 7 | |
| | | | | | | | | | | | | | | | | |
Lessor
The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each registrant and other terms and conditions of their lease agreements as of December 31, 2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Contracted generation | ● | | ● | | | | | | | | | | | | | | |
| Real estate | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in years) | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Remaining lease terms | 1-82 | | 1-31 | | 1-16 | | 1-82 | | 22 | | 1-12 | | 1-5 | | 11-12 | | 1 |
| Options to extend the term | 1-79 | | 1-5 | | 5-79 | | 5-50 | | N/A | | 5 | | N/A | | N/A | | N/A |
| | | | | | | | | | | | | | | | | |
The components of lease income were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 52 | | | $ | 47 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 3 | | | $ | 0 | | | $ | 3 | | | $ | 0 | |
| Variable lease income | 283 | | | 282 | | | 0 | | | 0 | | | 0 | | | 1 | | | 0 | | | 1 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 54 | | | $ | 47 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 5 | | | $ | 0 | | | $ | 4 | | | $ | 0 | |
| Variable lease income | 261 | | | 258 | | | 0 | | | 0 | | | 0 | | | 3 | | | 0 | | | 3 | | | 0 | |
Future minimum lease payments to be recovered under operating leases as of December 31, 2020 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2021 | $ | 51 | | | $ | 45 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 4 | | | $ | 1 | | | $ | 3 | | | $ | 0 | |
| 2022 | 50 | | | 45 | | | 0 | | | 0 | | | 0 | | | 4 | | | 0 | | | 3 | | | 0 | |
| 2023 | 49 | | | 45 | | | 0 | | | 0 | | | 0 | | | 4 | | | 0 | | | 4 | | | 0 | |
| 2024 | 49 | | | 45 | | | 0 | | | 0 | | | 0 | | | 3 | | | 0 | | | 3 | | | 0 | |
| 2025 | 48 | | | 45 | | | 0 | | | 0 | | | 0 | | | 4 | | | 0 | | | 4 | | | 0 | |
| Remaining years | 217 | | | 182 | | | 1 | | | 4 | | | 1 | | | 31 | | | 0 | | | 31 | | | 0 | |
| Total | $ | 464 | | | $ | 407 | | | $ | 1 | | | $ | 4 | | | $ | 1 | | | $ | 50 | | | $ | 1 | | | $ | 48 | | | $ | — | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 12 — Asset Impairments
12. Asset Impairments (Exelon and Generation)
The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.
Antelope Valley Solar Facility
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and 0 impairment charge was recorded.
The United States Bankruptcy Court entered an order on June 20, 2020 confirming PG&E’s plan of reorganization. On July 1, 2020 the plan became effective, and PG&E emerged from bankruptcy. Under the confirmed plan, PG&E will continue to honor the existing PPA agreement with Antelope Valley.
See Note 17 - Debt and Credit Agreements for additional information.
New England Asset Group
During the first quarter of 2018, Mystic Unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire its Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. These events suggested that the carrying value of the New England asset group may be impaired. In the first quarter of 2018, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and 0 impairment charge was required.
In the third quarter of 2020, in conjunction with the retirement announcement of Mystic Units 8 and 9, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the estimated undiscounted future cash flows and fair value of the New England asset group were less than their carrying values. As a result, a pre-tax impairment charge of $500 million was recorded in the third quarter of 2020 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. See Note 7 - Early Plant Retirements for additional information.
Midwest Asset Group
In the third quarter of 2020, in conjunction with the retirement announcements of the Byron and Dresden nuclear plants, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the Midwest asset group and 0 impairment charge was required.
Generation will continue to monitor the recoverability of the carrying value of the Midwest asset group as certain other nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement. See Note 7 - Early Plant Retirements for additional information.
Equity Method Investments in Certain Distributed Energy Companies
In the third quarter of 2019, Generation’s equity method investments in certain distributed energy companies were fully impaired due to an other-than-temporary decline in market conditions and underperforming projects.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 12 — Asset Impairments
Exelon and Generation recorded a pre-tax impairment charge of $164 million in Equity in losses of unconsolidated affiliates and an offsetting pre-tax $96 million in Net income attributable to noncontrolling interests in their Consolidated Statements of Operations and Comprehensive Income. As a result, Generation accelerated the amortization of investment tax credits associated with these companies and Exelon and Generation recorded a benefit of $46 million in Income taxes. The impairment charge and the accelerated amortization of investment tax credits resulted in a net $15 million decrease to Exelon’s and Generation’s earnings. See Note 23 — Variable Interest Entities for additional information.
13. Intangible Assets (Exelon, Generation, ComEd, PECO, PHI, Pepco, DPL, and ACE)
Goodwill
Exelon’s, ComEd’s and PHI'sThe following table presents the gross amount, of goodwill, accumulated impairment lossesloss, and carrying amount of goodwill forat Exelon, ComEd, and PHI as of December 31, 2020 and 2019. There were 0 additions or impairments during the years ended December 31, 20182020 and 2017 were as follows:2019.
|
| | | | | | | | | | | | | | | | | | | |
| | Balance at January 1, 2017 | | Impairment losses | | Balance at December 31, 2017 | | Impairment losses | | Balance at December 31, 2018 |
| Exelon | | | | | | | | | |
| Gross amount | $ | 8,660 |
| | $ | — |
| | $ | 8,660 |
| | $ | — |
| | $ | 8,660 |
|
| Accumulated impairment loss | 1,983 |
| | — |
| | 1,983 |
| | — |
| | 1,983 |
|
| Carrying amount | 6,677 |
| | — |
| | 6,677 |
| | — |
| | 6,677 |
|
ComEd(a) | | | | | | | | |
|
| Gross amount | 4,608 |
| | — |
| | 4,608 |
| | — |
| | 4,608 |
|
| Accumulated impairment loss | 1,983 |
| | — |
| | 1,983 |
| | — |
| | 1,983 |
|
| Carrying amount | 2,625 |
| | — |
| | 2,625 |
| | — |
| | 2,625 |
|
PHI(b) | | | | | | | | | |
| Gross amount | 4,005 |
| | — |
| | 4,005 |
| | — |
| | 4,005 |
|
| Carrying amount | 4,005 |
| | — |
| | 4,005 |
| | — |
| | 4,005 |
|
| | | | | | | | | | | | | | | | | |
| Gross Amount | | Accumulated Impairment Loss | | Carrying Amount |
| Exelon | $ | 8,660 | | | $ | 1,983 | | | $ | 6,677 | |
ComEd(a) | 4,608 | | | 1,983 | | | 2,625 | |
PHI(b) | 4,005 | | | 0 | | | 4,005 | |
__________
| |
(a) | Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd). |
| |
(b) | Reflects goodwill recorded in 2016 from the PHI merger. |
(a)Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).
(b)Reflects goodwill recorded in 2016 from the PHI merger.
Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is testedassessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 245 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment testingassessment purposes. Exelon's and ComEd's $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit. PHI identified an error related to the allocation of goodwill to its reporting units in 2016unit, while performing the 2018 annual impairment assessment. As revised in 2018, Exelon's and PHI's $4$4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively, an increase (decrease) of $0.4 billion, $0.3 billion, and $(0.7) billion for Pepco, DPL and ACE, respectively, from the originally reported amounts. This error did not result in a change to the total amount of goodwill recorded at PHI nor would it have resulted in an impairment of PHI's goodwill in 2016 or 2017. Therefore, management has concluded that the error is not material to the previously issued financial statements.respectively.
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing aAs part of the qualitative assessment, entities should assess,assessments, Exelon, ComEd, and PHI evaluate, among other things, macroeconomicmanagement's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, industryincluding the discount rate and market considerations, overall financial performance, cost factorsregulated utility peer EBITDA multiples, and entity-specific events. If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required.
passing margin from their last quantitative assessments performed. If an entity bypasses the qualitative assessment, or performs the qualitative assessment but determines that it is more likely than not that its fair value is less than its carrying amount, a quantitative, two-step, fair value-based testassessment is performed. Exelon's, ComEd's and PHI's accounting policy is to perform a quantitative test of goodwill at least once every three years. The first step in the quantitative testperformed, which compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second stepentity recognizes an impairment charge, which is performed. The second step requires an allocation of fair valuelimited to the individual assets and liabilities using purchase price allocation authoritative guidance in order to determine the implied fair value of goodwill. If the implied
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
fair valueamount of goodwill is less thanallocated to the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense.reporting unit.
Application of the goodwill impairment testassessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd's, Pepco's, DPL's, and ACE's businesses, and the fair value of debt. In applying the second step (if needed), management must estimate the fair value
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Intangible Assets
2020 and liabilities of the reporting unit.
2018 and 20172019 Goodwill Impairment Assessment. ComEd and PHI qualitatively determined that it was more likely than not that the fair values of their reporting units exceeded their carrying values and, therefore, did not perform quantitative assessments as of November 1, 20182020 and 20172019 for ComEd and PHI. The last quantitative assessments performed were as of November 1, 20172016 for PHI. As part of their qualitative assessments, ComEd and PHI evaluated, among other things, management’s best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer company EBITDA multiples, while also considering, the passing margin from their last quantitative assessments as of November 1, 2016.
As a result of the reallocation of goodwill to PHI’s reporting units as discussed above, as of November 1, 2018 PHI performed a quantitative test for its 2018 annual goodwill impairment assessment. The first step of the test comparing the estimated fair values of the Pepco, DPL and ACE reporting units to their carrying values, including goodwill, indicated no impairments of goodwill; therefore, no second step was required.PHI.
While the annual assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's, and PHI’s goodwill, which could be material. Based on the results of the annual goodwill test performed as of November 1, 2016 and November 1, 2018 for ComEd and PHI, respectively, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 30%, 20% and 30%, respectively, for ComEd and PHI to fail the first step of their respective impairment tests.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Other Intangible Assets and Liabilities
Exelon’s, Generation’s, ComEd’s, and PHI's other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities and Other deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 20182020 and 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2018 | | December 31, 2017 |
| | | Gross | | Accumulated Amortization | | Net | | Gross | | Accumulated Amortization | | Net |
| Generation | | | | | |
| | | | | |
|
Unamortized Energy Contracts(b) | | 1,957 |
| | (1,588 | ) | | 369 |
| | 1,938 |
| | (1,574 | ) | | 364 |
|
| Customer Relationships | | 325 |
| | (162 | ) | | 163 |
| | 305 |
| | (133 | ) | | 172 |
|
| Trade Name | | 243 |
| | (171 | ) | | 72 |
| | 243 |
| | (148 | ) | | 95 |
|
| ComEd | | | | | |
| | | | | |
|
Chicago Settlement Agreements(c) | | 162 |
| | (148 | ) | | 14 |
| | 162 |
| | (141 | ) | | 21 |
|
| PHI | | | | | |
| | | | | |
|
Unamortized Energy Contracts(b) | | (1,515 | ) | | 954 |
| | (561 | ) | | (1,515 | ) | | 766 |
| | (749 | ) |
| Exelon Corporate | | | | | | | | | | | | |
Software License(a) | | 95 |
| | (34 | ) | | 61 |
| | 95 |
| | (25 | ) | | 70 |
|
| Exelon | | $ | 1,267 |
| | $ | (1,149 | ) | | $ | 118 |
| | $ | 1,228 |
| | $ | (1,255 | ) | | $ | (27 | ) |
__________
| |
(a) | On May 31, 2015, Exelon entered into a long-term software license agreement. Exelon is required to make payments starting August 2015 through May 2024.2019. The intangible asset recognized as a result of these payments is being amortized on a straight-line basis over the contract term. |
| |
(b) | Includes unamortized energy contract assets and liabilities in Exelon's, Generations and PHI's Consolidated Balance Sheets. |
| |
(c) | In March 1999 and February 2003, ComEd entered into separate agreements with the City of Chicago and Midwest Generation, LLC. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement. |
The following table summarizes the estimated future amortization expense related to intangible assets and liabilities asshown below are amortized on a straight line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of December 31, 2018:the underlying cash flows:
|
| | | | | | | | | | | | | | | | |
| For the Years Ending December 31, | | Exelon | | Generation | | ComEd | | PHI |
| 2019 | | $ | (32 | ) | | $ | 70 |
| | $ | 7 |
| | $ | (119 | ) |
| 2020 | | (20 | ) | | 78 |
| | 7 |
| | (115 | ) |
| 2021 | | (4 | ) | | 78 |
| | — |
| | (92 | ) |
| 2022 | | (23 | ) | | 56 |
| | — |
| | (89 | ) |
| 2023 | | (21 | ) | | 50 |
| | — |
| | (81 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2020 | | December 31, 2019 |
| | Gross | | Accumulated Amortization | | Net | | Gross | | Accumulated Amortization | | Net |
| Generation | | | | | | | | | | | | |
| Unamortized Energy Contracts | | $ | 1,963 | | | $ | (1,642) | | | $ | 321 | | | $ | 1,967 | | | $ | (1,612) | | | $ | 355 | |
| Customer Relationships | | 326 | | | (215) | | | 111 | | | 343 | | | (190) | | | 153 | |
| Trade Name | | 222 | | | (197) | | | 25 | | | 243 | | | (193) | | | 50 | |
| | | | | | | | | | | | |
| ComEd | | | | | | | | | | | | |
| Chicago Settlement Agreements | | 162 | | | (162) | | | 0 | | | 162 | | | (155) | | | 7 | |
| PHI | | | | | | | | | | | | |
| Unamortized Energy Contracts | | (1,515) | | | 1,188 | | | (327) | | | (1,515) | | | 1,073 | | | (442) | |
| Exelon Corporate | | | | | | | | | | | | |
| Software License | | 95 | | | (53) | | | 42 | | | 95 | | | (44) | | | 51 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Exelon | | $ | 1,253 | | | $ | (1,081) | | | $ | 172 | | | $ | 1,295 | | | $ | (1,121) | | | $ | 174 | |
The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2018, 20172020, 2019, and 2016:2018:
| | | For the Years Ended December 31, | | Exelon (a)(b) | | Generation (a) | | ComEd | | PHI(b) | For the Years Ended December 31, | | Exelon(a)(b) | | Generation(a) | | ComEd | | PHI(b) |
| 2020 | | 2020 | | $ | (17) | | | $ | 81 | | | $ | 7 | | | $ | (115) | |
| 2019 | | 2019 | | (28) | | | 74 | | | 7 | | | (119) | |
| 2018 | | $ | (109 | ) | | $ | 63 |
| | $ | 7 |
| | $ | (188 | ) | 2018 | | (109) | | | 63 | | | 7 | | | (188) | |
| 2017 | | (237 | ) | | 83 |
| | 7 |
| | (336 | ) | |
| 2016 | | (336 | ) | | 79 |
| | 7 |
| | (430 | ) | |
__________
| |
(a) | At Exelon and Generation, amortization of unamortized energy contracts totaling $14 million, $35 million and $35 million for the years ended December 31, 2018, 2017 and 2016, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income. |
(a)At Exelon and Generation, amortization of unamortized energy contracts totaling $30 million, $21 million, and $14 million for the years ended December 31, 2020, 2019, and 2018, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.
(b)At Exelon and PHI, amortization of the unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.
The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ending December 31, | | Exelon | | Generation | | | | PHI |
| 2021 | | $ | (1) | | | $ | 81 | | | | | $ | (92) | |
| 2022 | | (22) | | | 57 | | | | | (89) | |
| 2023 | | (20) | | | 51 | | | | | (81) | |
| 2024 | | 20 | | | 48 | | | | | (38) | |
| 2025 | | 40 | | | 41 | | | | | (5) | |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(b) | At Exelon and PHI, amortization of the unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income. |
AcquiredNote 13 — Intangible Assets and Liabilities
Business combinations require the acquirer to separately recognize identifiable intangible assets in the application of purchase accounting.
Unamortized Energy Contracts. Unamortized energy contract assets and liabilities represent the remaining unamortized fair value of non-derivative energy contracts that Exelon and Generation have acquired. The valuation of unamortized energy contracts was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise, the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable authoritative guidance. Key estimates and inputs include forecasted power and fuel prices and the discount rate. The Exelon Wind unamortized energy contracts are amortized on a straight-line basis over the period in which the associated contract revenues are recognized as a decrease in Operating revenues within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. In the case of Antelope Valley, Constellation, CENG, Integrys and ConEdison, the fair value amounts are amortized over the life of the contract in relation to the present value of the underlying cash flows as of the acquisition dates through either Operating revenues or Purchased power and fuel expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. At PHI, offsetting regulatory assets or liabilities were also recorded. The unamortized energy contract assets and liabilities and any corresponding regulatory assets or liabilities, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows.
Customer Relationships. The customer relationship intangibles were determined based on a “multi-period excess method” of the income approach. Under this method, the intangible asset’s fair value is determined to be the estimated future cash flows that will be earned on the current customer base, taking into account expected contract renewals based on customer attrition rates and costs to retain those customers. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable authoritative guidance. Key assumptions include the customer attrition rate and the discount rate. The authoritative guidance requires that customer-based intangibles be amortized over the period expected to be benefited using the pattern of economic benefit. The amortization of the customer relationships recorded in Depreciation and amortization expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
Trade Name. The Constellation trade name intangible was determined based on the relief from royalty method of income approach whereby fair value is determined to be the present value of the license fees avoided by owning the assets. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable authoritative guidance. Key assumptions include the hypothetical royalty rate and the discount rate. The Constellation trade name intangible is amortized on a straight-line basis over a period of 10 years. The amortization of the trade name is recorded in Depreciation and amortization expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
Renewable Energy Credits (Exelon and Alternative Energy Credits (Exelon, Generation, PECO, PHI, DPL and ACE)Generation)
Exelon’s and Generation’s PECO's, PHI's, DPL's and ACE's other intangible assets,RECs are included in Other current assets and Other deferred debits and other assets in the Consolidated Balance Sheets, include RECs (Exelon, Generation, PHI, DPL and ACE) and AECs (Exelon and PECO).Sheets. Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer.
The following table presents the current and noncurrent RECs as of December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2020 | | As of December 31, 2019 |
| Exelon | | Generation | | Exelon | | Generation |
| Current REC's | $ | 632 | | | $ | 621 | | | $ | 345 | | | $ | 336 | |
| Noncurrent REC's | 0 | | | 0 | | | 86 | | | 86 | |
14. Income Taxes (All Registrants)
Components of Income Tax Expense or Benefit
Income tax expense (benefit) from continuing operations is comprised of the following components:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2020 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Included in operations: | | | | | | | | | | | | | | | | | |
| Federal | | | | | | | | | | | | | | | | | |
| Current | $ | 26 | | | $ | 130 | | | $ | (24) | | | $ | (7) | | | $ | 4 | | | $ | 25 | | | $ | 40 | | | $ | (13) | | | $ | (4) | |
| Deferred | 156 | | | 150 | | | 112 | | | 1 | | | 10 | | | (129) | | | (62) | | | (20) | | | (43) | |
| Investment tax credit amortization | (28) | | | (25) | | | (2) | | | 0 | | | 0 | | | (1) | | | 0 | | | 0 | | | 0 | |
| State | | | | | | | | | | | | | | | | | |
| Current | 42 | | | 40 | | | (27) | | | 0 | | | 0 | | | (5) | | | 0 | | | 0 | | | 0 | |
| Deferred | 177 | | | (46) | | | 118 | | | (24) | | | 27 | | | 33 | | | 15 | | | 8 | | | 6 | |
| Total | $ | 373 | | | $ | 249 | | | $ | 177 | | | $ | (30) | | | $ | 41 | | | $ | (77) | | | $ | (7) | | | $ | (25) | | | $ | (41) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2019 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Included in operations: | | | | | | | | | | | | | | | | | |
| Federal | | | | | | | | | | | | | | | | | |
| Current | $ | 85 | | | $ | 147 | | | $ | 59 | | | $ | 45 | | | $ | (51) | | | $ | 43 | | | $ | 16 | | | $ | 29 | | | $ | (3) | |
| Deferred | 489 | | | 346 | | | 15 | | | 20 | | | 95 | | | (34) | | | (6) | | | (21) | | | (6) | |
| Investment tax credit amortization | (72) | | | (69) | | | (2) | | | 0 | | | 0 | | | (1) | | | 0 | | | 0 | | | 0 | |
| State | | | | | | | | | | | | | | | | | |
| Current | 5 | | | 10 | | | (5) | | | 0 | | | 0 | | | 3 | | | 0 | | | 0 | | | 0 | |
| Deferred | 267 | | | 82 | | | 96 | | | 0 | | | 35 | | | 27 | | | 6 | | | 14 | | | 9 | |
| Total | $ | 774 | | | $ | 516 | | | $ | 163 | | | $ | 65 | | | $ | 79 | | | $ | 38 | | | $ | 16 | | | $ | 22 | | | $ | 0 | |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2018 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Included in operations: | | | | | | | | | | | | | | | | | |
| Federal | | | | | | | | | | | | | | | | | |
| Current | $ | 226 | | | $ | 337 | | | $ | (63) | | | $ | 11 | | | $ | (5) | | | $ | (4) | | | $ | 28 | | | $ | (3) | | | $ | (14) | |
| Deferred | (99) | | | (347) | | | 145 | | | 10 | | | 47 | | | 23 | | | (22) | | | 13 | | | 18 | |
| Investment tax credit amortization | (24) | | | (21) | | | (2) | | | 0 | | | 0 | | | (1) | | | 0 | | | 0 | | | 0 | |
| State | | | | | | | | | | | | | | | | | |
| Current | (1) | | | 6 | | | (29) | | | 1 | | | 0 | | | 7 | | | 0 | | | 0 | | | 0 | |
| Deferred | 16 | | | (83) | | | 117 | | | (16) | | | 32 | | | 8 | | | 5 | | | 12 | | | 8 | |
| Total | $ | 118 | | | $ | (108) | | | $ | 168 | | | $ | 6 | | | $ | 74 | | | $ | 33 | | | $ | 11 | | | $ | 22 | | | $ | 12 | |
Rate Reconciliation
The following table summarizeseffective income tax rate from continuing operations varies from the current and noncurrent Renewable and Alternative Energy Credits asU.S. federal statutory rate principally due to the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2020(a) |
| Exelon | | Generation | | ComEd(b) | | PECO(c) | | BGE(d) | | PHI(d) | | Pepco(d) | | DPL(d) | | ACE(d) |
| U.S. federal statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
| State income taxes, net of Federal income tax benefit | 7.8 | | | 0.5 | | | 11.6 | | | (4.5) | | | 5.5 | | | 5.1 | | | 4.5 | | | 6.6 | | | 7.0 | |
| Qualified NDT fund income | 8.4 | | | 23.5 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred Prosecution Agreement payments | 1.8 | | | 0 | | | 6.8 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.1) | | | (2.6) | | | (0.3) | | | 0 | | | (0.1) | | | (0.2) | | | (0.1) | | | (0.3) | | | (0.5) | |
| Plant basis differences | (4.0) | | | 0 | | | (0.6) | | | (18.7) | | | (1.5) | | | (1.6) | | | (1.7) | | | (0.4) | | | (3.0) | |
| Production tax credits and other credits | (2.2) | | | (5.4) | | | (0.3) | | | 0 | | | (0.4) | | | (0.3) | | | (0.3) | | | (0.3) | | | (0.5) | |
| Noncontrolling interests | 1.1 | | | 3.2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Excess deferred tax amortization | (13.6) | | | 0 | | | (11.2) | | | (4.6) | | | (13.9) | | | (42.0) | | | (25.4) | | | (51.7) | | | (82.1) | |
| Tax settlements | (3.7) | | | (10.3) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Other | 0.5 | | | (0.1) | | | 1.8 | | | (0.4) | | | (0.1) | | | (0.4) | | | (0.7) | | | 0.1 | | | 0.4 | |
| Effective income tax rate | 16.0 | % | | 29.8 | % | | 28.8 | % | | (7.2) | % | | 10.5 | % | | (18.4) | % | | (2.7) | % | | (25.0) | % | | (57.7) | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2019(a) |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| U.S. federal statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
| State income taxes, net of Federal income tax benefit | 5.4 | | | 3.8 | | | 8.5 | | | 0 | | | 6.4 | | | 4.7 | | | 2.0 | | | 6.8 | | | 7.0 | |
| Qualified NDT fund income | 5.9 | | | 12.3 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.5) | | | (3.0) | | | (0.2) | | | 0 | | | (0.1) | | | (0.2) | | | (0.1) | | | (0.2) | | | (0.3) | |
| Plant basis differences | (1.4) | | | 0 | | | 0 | | | (7.2) | | | (1.2) | | | (1.2) | | | (1.8) | | | (0.4) | | | (0.7) | |
| Production tax credits and other credits | (3.1) | | | (4.8) | | | (1.2) | | | 0 | | | (1.3) | | | (0.2) | | | (0.1) | | | 0 | | | (0.1) | |
| Noncontrolling interests | (0.6) | | | (1.2) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Excess deferred tax amortization | (5.5) | | | 0 | | | (9.7) | | | (2.8) | | | (6.8) | | | (17.5) | | | (15.1) | | | (14.2) | | | (27.0) | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Other | (0.8) | | | (1.2) | | | 0.8 | | | 0 | | | 0 | | | 0.8 | | | 0.3 | | | 0 | | | 0.1 | |
| Effective income tax rate | 19.4 | % | | 26.9 | % | | 19.2 | % | | 11.0 | % | | 18.0 | % | | 7.4 | % | | 6.2 | % | | 13.0 | % | | 0 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, 2018 |
| | Exelon | | Generation | | PECO | | PHI | | DPL | | ACE |
| Current AEC's | $ | 2 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Current REC's | 279 |
| | 270 |
| | — |
| | 9 |
| | 8 |
| | 1 |
|
| Noncurrent REC's | 52 |
| | 52 |
| | — |
| | — |
| | — |
| | — |
|
| | As of December 31, 2017 |
| | Exelon | | Generation | | PECO | | PHI | | DPL | | ACE |
| Current AEC's | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Current REC's | 321 |
| | 312 |
| | — |
| | 9 |
| | 8 |
| | 1 |
|
| Noncurrent REC's | 27 |
| | 27 |
| | — |
| | — |
| | — |
| | — |
|
11. Fair Value of Financial Assets and Liabilities (All Registrants)
Fair Value of Financial Liabilities Recorded at the Carrying Amount
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 2018 and 2017:
Exelon
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | Carrying
Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| Short-term liabilities | $ | 714 |
| | $ | — |
|
| $ | 714 |
|
| $ | — |
| | $ | 714 |
|
Long-term debt (including amounts due within one year)(a) | 35,424 |
| | — |
|
| 33,711 |
|
| 2,158 |
| | 35,869 |
|
Long-term debt to financing trusts(b) | 390 |
| | — |
|
| — |
|
| 400 |
| | 400 |
|
| SNF obligation | 1,171 |
| | — |
|
| 949 |
|
| — |
| | 949 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| Short-term liabilities | $ | 929 |
| | $ | — |
| | $ | 929 |
| | $ | — |
| | $ | 929 |
|
Long-term debt (including amounts due within one year)(a) | 34,264 |
| | — |
| | 34,735 |
| | 1,970 |
| | 36,705 |
|
Long-term debt to financing trusts(b) | 389 |
| | — |
| | — |
| | 431 |
| | 431 |
|
| SNF obligation | 1,147 |
| | — |
| | 936 |
| | — |
| | 936 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
Generation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2018(a) |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| U.S. federal statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
| State income taxes, net of Federal income tax benefit | 0.5 | | | (16.6) | | | 8.3 | | | (2.6) | | | 6.6 | | | 2.9 | | | 2.0 | | | 6.7 | | | 7.4 | |
| Qualified NDT fund income | (1.9) | | | (11.8) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.2) | | | (6.5) | | | (0.2) | | | (0.1) | | | (0.1) | | | (0.2) | | | (0.1) | | | (0.3) | | | (0.4) | |
| Plant basis differences | (3.5) | | | 0 | | | (0.2) | | | (14.1) | | | (1.3) | | | (1.6) | | | (2.8) | | | (0.3) | | | (0.5) | |
| Production tax credits and other credits | (2.2) | | | (13.5) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Noncontrolling interests | (1.0) | | | (6.1) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Excess deferred tax amortization | (8.3) | | | 0 | | | (9.1) | | | (3.2) | | | (8.0) | | | (14.8) | | | (15.3) | | | (12.0) | | | (14.9) | |
| Tax Cuts and Jobs Act of 2017 | 0.9 | | | 2.7 | | | (0.1) | | | 0 | | | 0 | | | 0.1 | | | 0 | | | 0 | | | 0 | |
| Other | 1.0 | | | 1.3 | | | 0.5 | | | 0.3 | | | 0.9 | | | 0.4 | | | 0.3 | | | 0.4 | | | 1.2 | |
| Effective income tax rate | 5.3 | % | | (29.5) | % | | 20.2 | % | | 1.3 | % | | 19.1 | % | | 7.8 | % | | 5.1 | % | | 15.5 | % | | 13.8 | % |
__________
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. See Note 19 — Commitments and Contingencies for additional information.
(c)At PECO, the negative effective tax rate is primarily related to an increase in plant basis differences attributable to tax repair deductions related to an increase in storms and qualifying projects.
(d)At BGE, the lower effective tax rate, and at PHI, Pepco, DPL, and ACE, the negative effective tax rate is primarily attributable to accelerated amortization of transmission related income tax regulatory liabilities as a result of regulatory settlements. See Note 3 — Regulatory Matters for additional information.
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
Long-term debt (including amounts due within one year)(a) | $ | 8,793 |
| | $ | — |
|
| $ | 7,467 |
|
| $ | 1,443 |
| | $ | 8,910 |
|
| SNF obligation | 1,171 |
| | — |
|
| 949 |
|
| — |
| | 949 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| Short-term liabilities | $ | 2 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | 2 |
|
Long-term debt (including amounts due within one year)(a) | 8,990 |
| | — |
| | 7,839 |
| | 1,673 |
| | 9,512 |
|
| SNF obligation | 1,147 |
| | — |
| | 936 |
| | — |
| | 936 |
|
ComEd
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
Long-term debt (including amounts due within one year)(a) | $ | 8,101 |
| | $ | — |
|
| $ | 8,390 |
|
| $ | — |
| | $ | 8,390 |
|
Long-term debt to financing trusts(b) | 205 |
| | — |
|
| — |
|
| 209 |
| | 209 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
Long-term debt (including amounts due within one year)(a) | $ | 7,601 |
| | $ | — |
| | $ | 8,418 |
| | $ | — |
| | $ | 8,418 |
|
Long-term debt to financing trusts(b) | 205 |
| | — |
| | — |
| | 227 |
| | 227 |
|
PECO
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
Long-term debt (including amounts due within one year)(a) | $ | 3,084 |
| | $ | — |
|
| $ | 3,157 |
|
| $ | 50 |
| | $ | 3,207 |
|
| Long-term debt to financing trusts | 184 |
| | — |
|
| — |
|
| 191 |
| | 191 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
Long-term debt (including amounts due within one year)(a) | $ | 2,903 |
| | $ | — |
| | $ | 3,194 |
| | $ | — |
| | $ | 3,194 |
|
| Long-term debt to financing trusts | 184 |
| | — |
| | — |
| | 204 |
| | 204 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
BGETax Differences and Carryforwards
The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2020 and 2019 are presented below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2020 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Plant basis differences | $ | (13,868) | | | $ | (2,592) | | | $ | (4,432) | | | $ | (2,131) | | | $ | (1,711) | | | $ | (2,822) | | | $ | (1,259) | | | $ | (806) | | | $ | (725) | |
| Accrual based contracts | 40 | | | (37) | | | 0 | | | 0 | | | 0 | | | 77 | | | 0 | | | 0 | | | 0 | |
| Derivatives and other financial instruments | 41 | | | (41) | | | 84 | | | 0 | | | 0 | | | 2 | | | 0 | | | 0 | | | 0 | |
| Deferred pension and postretirement obligation | 1,559 | | | (236) | | | (288) | | | (30) | | | (33) | | | (80) | | | (74) | | | (40) | | | (7) | |
| Nuclear decommissioning activities | (742) | | | (742) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred debt refinancing costs | 169 | | | 16 | | | (6) | | | 0 | | | (2) | | | 131 | | | (3) | | | (1) | | | (1) | |
| Regulatory assets and liabilities | (1,107) | | | 0 | | | 87 | | | (231) | | | 142 | | | (41) | | | 38 | | | 67 | | | 46 | |
| Tax loss carryforward | 286 | | | 55 | | | 0 | | | 47 | | | 57 | | | 90 | | | 4 | | | 49 | | | 38 | |
| Tax credit carryforward | 841 | | | 838 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Investment in partnerships | (835) | | | (813) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Other, net | 1,070 | | | 347 | | | 223 | | | 104 | | | 29 | | | 220 | | | 107 | | | 18 | | | 27 | |
| Deferred income tax liabilities (net) | $ | (12,546) | | | $ | (3,205) | | | $ | (4,332) | | | $ | (2,241) | | | $ | (1,518) | | | $ | (2,423) | | | $ | (1,187) | | | $ | (713) | | | $ | (622) | |
Unamortized investment tax credits(a) | (464) | | | (445) | | | (9) | | | (1) | | | (3) | | | (6) | | | (2) | | | (2) | | | (3) | |
| Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (13,010) | | | $ | (3,650) | | | $ | (4,341) | | | $ | (2,242) | | | $ | (1,521) | | | $ | (2,429) | | | $ | (1,189) | | | $ | (715) | | | $ | (625) | |
__________
(a)Does not include unamortized investment tax credits reclassified to liabilities held for sale.
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| Short-term liabilities | $ | 35 |
| | $ | — |
|
| $ | 35 |
|
| $ | — |
| | $ | 35 |
|
Long-term debt (including amounts due within one year)(a) | 2,876 |
| | — |
|
| 2,950 |
|
| — |
| | 2,950 |
|
291
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| Short-term liabilities | $ | 77 |
| | $ | — |
| | $ | 77 |
| | $ | — |
| | $ | 77 |
|
Long-term debt (including amounts due within one year)(a) | 2,577 |
| | — |
| | 2,825 |
| | — |
| | 2,825 |
|
PHI
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | Carrying Amount | | Fair Value |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| Short-term liabilities | $ | 179 |
| | $ | — |
| | $ | 179 |
| | $ | — |
| | $ | 179 |
|
Long-term debt (including amounts due within one year)(a) | 6,259 |
| | — |
| | 5,436 |
| | 665 |
| | 6,101 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Carrying Amount | | Fair Value |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| Short-term liabilities | $ | 350 |
| | $ | — |
| | $ | 350 |
| | $ | — |
| | $ | 350 |
|
Long-term debt (including amounts due within one year)(a) | 5,874 |
| | — |
| | 5,722 |
| | 297 |
| | 6,019 |
|
Pepco
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | Carrying Amount | | Fair Value |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| Short-term liabilities | $ | 40 |
| | $ | — |
| | $ | 40 |
| | $ | — |
| | $ | 40 |
|
Long-term debt (including amounts due within one year)(a) | 2,719 |
| | — |
| | 2,901 |
| | 196 |
| | 3,097 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Carrying Amount | | Fair Value |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| Short-term liabilities | $ | 26 |
| | $ | — |
| | $ | 26 |
| | $ | — |
| | $ | 26 |
|
Long-term debt (including amounts due within one year)(a) | 2,540 |
| | — |
| | 3,114 |
| | 9 |
| | 3,123 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
DPL
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | Carrying Amount | | Fair Value |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
Long-term debt (including amounts due within one year)(a) | $ | 1,494 |
| | $ | — |
| | $ | 1,303 |
| | $ | 193 |
| | $ | 1,496 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2019 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Plant basis differences | $ | (13,413) | | | $ | (2,814) | | | $ | (4,197) | | | $ | (1,978) | | | $ | (1,578) | | | $ | (2,681) | | | $ | (1,204) | | | $ | (753) | | | $ | (687) | |
| Accrual based contracts | 61 | | | (43) | | | 0 | | | 0 | | | 0 | | | 104 | | | 0 | | | 0 | | | 0 | |
| Derivatives and other financial instruments | 165 | | | 88 | | | 84 | | | 0 | | | 0 | | | 2 | | | 0 | | | 0 | | | 0 | |
| Deferred pension and postretirement obligation | 1,504 | | | (220) | | | (270) | | | (28) | | | (28) | | | (89) | | | (75) | | | (42) | | | (10) | |
| Nuclear decommissioning activities | (503) | | | (503) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred debt refinancing costs | 183 | | | 20 | | | (7) | | | 0 | | | (3) | | | 142 | | | (3) | | | (2) | | | (1) | |
| Regulatory assets and liabilities | (884) | | | 0 | | | 183 | | | (169) | | | 157 | | | (10) | | | 55 | | | 88 | | | 77 | |
| Tax loss carryforward | 240 | | | 55 | | | 0 | | | 25 | | | 49 | | | 93 | | | 13 | | | 44 | | | 31 | |
| Tax credit carryforward | 892 | | | 897 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Investment in partnerships | (830) | | | (808) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Other, net | 926 | | | 236 | | | 196 | | | 70 | | | 10 | | | 181 | | | 85 | | | 12 | | | 16 | |
| Deferred income tax liabilities (net) | $ | (11,659) | | | $ | (3,092) | | | $ | (4,011) | | | $ | (2,080) | | | $ | (1,393) | | | $ | (2,258) | | | $ | (1,129) | | | $ | (653) | | | $ | (574) | |
| Unamortized investment tax credits | (668) | | | (648) | | | (10) | | | (1) | | | (3) | | | (7) | | | (2) | | | (2) | | | (3) | |
Total deferred income tax liabilities (net) and
unamortized investment tax credits | $ | (12,327) | | | $ | (3,740) | | | $ | (4,021) | | | $ | (2,081) | | | $ | (1,396) | | | $ | (2,265) | | | $ | (1,131) | | | $ | (655) | | | $ | (577) | |
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Carrying Amount | | Fair Value |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| Short-term liabilities | $ | 216 |
| | $ | — |
| | $ | 216 |
| | $ | — |
| | $ | 216 |
|
Long-term debt (including amounts due within one year)(a) | 1,300 |
| | — |
| | 1,393 |
| | — |
| | 1,393 |
|
ACE
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | Carrying Amount | | Fair Value |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| Short-term liabilities | $ | 139 |
| | $ | — |
| | $ | 139 |
| | $ | — |
| | $ | 139 |
|
Long-term debt (including amounts due within one year)(a) | 1,188 |
| | — |
| | 987 |
| | 275 |
| | 1,262 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Carrying Amount | | Fair Value |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| Short-term liabilities | $ | 108 |
| | $ | — |
| | $ | 108 |
| | $ | — |
| | $ | 108 |
|
Long-term debt (including amounts due within one year)(a) | 1,121 |
| | — |
| | 949 |
| | 288 |
| | 1,237 |
|
__________
(a) Includes unamortized debt issuance costsThe following table provides Exelon’s, Generation’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s, and ACE’s carryforwards, which are not fair valued of $216 million, $51 million, $63 million, $23 million, $18 million, $14 million, $34 million, $12 millionpresented on a post-apportioned basis, and $7 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE respectively,any corresponding valuation allowances as of December 31, 2018. Includes unamortized debt issuance costs which2020. ComEd does not have net operating losses or credit carryforwards for the year ended December 31, 2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Federal | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Federal general business credits carryforwards and other carryforwards | $ | 858 | | | $ | 852 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| State | | | | | | | | | | | | | | | |
| State net operating losses and other carryforwards | 5,202 | | | 1,118 | | | 616 | | | 902 | | | 1,436 | | | 63 | | | 728 | | | 531 | |
| Deferred taxes on state tax attributes (net) | 324 | | | 76 | | | 49 | | | 59 | | | 98 | | | 4 | | | 49 | | | 38 | |
| Valuation allowance on state tax attributes | 27 | | | 23 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Year in which net operating loss or credit carryforwards will begin to expire(a) | 2034 | | 2034 | | 2032 | | 2033 | | 2029 | | 2029 | | 2032 | | 2031 |
__________
(a)Generation's state net operating loss carryforwards will begin expiring in 2029. PECO's Pennsylvania charitable contribution carryforwards and BGE's Maryland charitable deduction and capital loss carryforwards will begin expiring in 2021. ACE's New Jersey tax credit carryforward has an indefinite carryforward period. These amounts are not fair valuedmaterial.
Tabular Reconciliation of $201 million, $60 million, $52 million, $17 million, $17 million, $6 million, $32 million, $11 million and $5 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE respectively, asUnrecognized Tax Benefits
The following table presents changes in unrecognized tax benefits, by Registrant.
(b) Includes unamortized debt issuance costs which are not fair valued of $0 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2018. Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2017.
Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of dividends payable (included in Other current liabilities) (Level 1) and short-term borrowings (Level 2). The Registrants’ carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments.
Long-Term Debt. The fair value amounts of Exelon’s taxable debt securities (Level 2) and private placement taxable debt securities (Level 3) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
bond or note. Due | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance at January 1, 2018 | $ | 743 | | | $ | 468 | | | $ | 2 | | | $ | 0 | | | $ | 120 | | | $ | 125 | | | $ | 59 | | | $ | 21 | | | $ | 14 | |
| Change to positions that only affect timing | 15 | | | 15 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Increases based on tax positions prior to 2018 | 30 | | | 21 | | | 0 | | | 0 | | | 0 | | | 8 | | | 7 | | | 1 | | | 0 | |
Decreases based on tax positions prior to 2018(a) | (251) | | | (36) | | | 0 | | | 0 | | | (120) | | | (88) | | | (66) | | | (22) | | | 0 | |
| Decrease from settlements with taxing authorities | (53) | | | (53) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Decreases from expiration of statute of limitations | (7) | | | (7) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance at December 31, 2018 | 477 | | | 408 | | | 2 | | | 0 | | | 0 | | | 45 | | | 0 | | | 0 | | | 14 | |
| Change to positions that only affect timing | 26 | | | 12 | | | 3 | | | 1 | | | 4 | | | 3 | | | 2 | | | 1 | | | 0 | |
| Increases based on tax positions related to 2019 | 2 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Increases based on tax positions prior to 2019 | 34 | | | 19 | | | 3 | | | 2 | | | 3 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Decreases based on tax positions prior to 2019 | (3) | | | (3) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Decrease from settlements with taxing authorities | (29) | | | 4 | | | (2) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance at December 31, 2019 | 507 | | | 441 | | | 6 | | | 3 | | | 7 | | | 48 | | | 2 | | | 1 | | | 14 | |
| Change to positions that only affect timing | 6 | | | 0 | | | 2 | | | 3 | | | 3 | | | 3 | | | 1 | | | 0 | | | 1 | |
| Increases based on tax positions related to 2020 | 3 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Increases based on tax positions prior to 2020 | 26 | | | 23 | | | 1 | | | 0 | | | 0 | | | 1 | | | 0 | | | 0 | | | 0 | |
Decreases based on tax positions prior to 2020(b) | (348) | | | (346) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Decrease from settlements with taxing authorities(b) | (69) | | | (69) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Balance at December 31, 2020 | $ | 125 | | | $ | 50 | | | $ | 9 | | | $ | 6 | | | $ | 10 | | | $ | 52 | | | $ | 3 | | | $ | 1 | | | $ | 15 | |
__________
(a)Exelon, Generation, BGE, PHI, Pepco, and DPL decreased their unrecognized state tax benefits primarily due to low trading volumethe receipt of private placement debt, qualitative factors such as market conditions, low volumefavorable guidance with respect to the deductibility of investorscertain depreciable fixed assets. The recognition of the tax benefits related to BGE, PHI, Pepco, and investor demand, this debt is classified as Level 3.DPL was offset by corresponding regulatory liabilities and that portion had no immediate impact to their effective tax rate.
The fair value of Generation’s(b)Exelon's and Pepco's non-government-backed fixed rate nonrecourse debt (Level 3) is based on marketGeneration's unrecognized federal and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volumestate tax benefits decreased in the nonrecourse debt market,first quarter of 2020 by approximately $411 million due to the price quotes usedsettlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developmentsExelon's and Generation’s net income of $76 million and $73 million, respectively, in the first quarter of 2020, reflecting a decrease to Exelon's and Generation's income tax expense of $67 million.
Like-Kind Exchange
In 2016, the Tax Court held that might significantly impactExelon was not entitled to defer a gain on its 1999 like-kind exchange transaction. In addition to the project cash flows or off-taker credit,tax and other circumstancesinterest related to the project (e.g., politicalgain deferral, the Tax Court also ruled that Exelon was liable for penalties and regulatory environment). The fair value of Generation’s government-backed fixed rate project financing debt (Level 3) is largely basedinterest on a discounted cash flow methodology that is similarthe penalties. Exelon had fully paid the amounts assessed resulting from the Tax Court decision in 2017. In September 2017, Exelon appealed the Tax Court decision to the taxable debt securities methodology described above. Due to the lackU.S. Court of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable Treasury rate as well as a current market curve derived from government-backed securities. Variable rate financing debt resets on a monthly or quarterly basis and the carrying value approximates fair value (Level 2). When trading data is available on variable rate financing debt, the fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles (Level 2). Generation, Pepco, DPL and ACE also have tax-exempt debt (Level 2). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (e.g., conduit issuer political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above. Variable rate tax-exempt debt (Level 2) resets on a regular basis and the carrying value approximates fair value.
SNF Obligation. The carrying amount of Generation’s SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount rate, which is calculated using the same methodology as described aboveAppeals for the taxable debt securities, and an estimated maturity dateSeventh Circuit. In October 2018, the U.S. Court of 2030. The carrying amount also includes $119 million and $114 million as of December 31, 2018 and 2017Appeals for the one-time fee obligation associated with closingSeventh Circuit affirmed the
Long-Term Debt to Financing Trusts. Exelon’s long-term debt to financing trusts is valued based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.
Recurring Fair Value Measurements
Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
GenerationTax Court’s decision. Exelon filed a petition seeking rehearing of the Seventh Circuit’s decision, but the Seventh Circuit denied that petition in December 2018. In the first quarter of 2019, Exelon elected not to seek a further review by the U.S. Supreme Court. As a result, Exelon's and Exelon
In accordance with the applicable guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share as a practical expedient are no longer classified within the fair value hierarchyComEd's unrecognized tax benefits decreased by approximately $33 million and are included under "Not subject to leveling"$2 million, respectively, in the table below.first quarter of 2019.
Recognition of unrecognized tax benefits
The following tablestable presents Exelon's, Generation's, and PHI's unrecognized tax benefits that, if recognized, would decrease the effective tax rate. ComEd's, PECO's, BGE's, Pepco's, DPL's, and ACE's amounts are not material.
| | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | PHI(a) | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| December 31, 2020 | $ | 73 | | | $ | 39 | | | $ | 33 | | | | | | | |
| December 31, 2019 | 462 | | | 429 | | | 32 | | | | | | | |
| December 31, 2018 | 463 | | | 408 | | | 31 | | | | | | | |
__________
(a)PHI has $21 million of unrecognized state tax benefits that, if recognized, $14 million would be in the form of a net operating loss carryforward, which is expected to require a full valuation allowance based on present assets and liabilities measured and recorded at fair value in Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchycircumstances.
ACE has $14 million of unrecognized tax benefits as of December 31, 2020, 2019 and 2018 that, if recognized, may be included in future base rates and 2017:that portion would have no impact on the effective tax rate. Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI's, Pepco's, and DPL's amounts are not material.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
As of December 31, 2020, ACE has approximately $14 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date based on the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Total amounts of interest and penalties recognized
The following table represents the net interest and penalties receivable (payable) related to tax positions reflected in Exelon's Consolidated Balance Sheets. Generation's and the Utility Registrants' amounts are not material.
| | | | | |
| Net interest and penalties receivable as of | Exelon |
| December 31, 2020 | $ | 314 | |
| December 31, 2019 | 318 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | Exelon |
| As of December 31, 2018 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Assets | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 581 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 581 |
| | $ | 1,243 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,243 |
|
| NDT fund investments | | | | | | | | |
|
| | | | | | | | | |
|
|
Cash equivalents(b) | 252 |
| | 86 |
| | — |
| | — |
| | 338 |
| | 252 |
| | 86 |
| | — |
| | — |
| | 338 |
|
| Equities | 2,918 |
| | 1,591 |
| | — |
| | 1,381 |
| | 5,890 |
| | 2,918 |
| | 1,591 |
| | — |
| | 1,381 |
| | 5,890 |
|
| Fixed income |
| |
| |
| | | |
|
| |
| |
| |
| | | |
|
|
| Corporate debt | — |
| | 1,593 |
| | 230 |
| | — |
| | 1,823 |
| | — |
| | 1,593 |
| | 230 |
| | — |
| | 1,823 |
|
| U.S. Treasury and agencies | 2,081 |
| | 99 |
| | — |
| | — |
| | 2,180 |
| | 2,081 |
| | 99 |
| | — |
| | — |
| | 2,180 |
|
| Foreign governments | — |
| | 50 |
| | — |
| | — |
| | 50 |
| | — |
| | 50 |
| | — |
| | — |
| | 50 |
|
| State and municipal debt | — |
| | 149 |
| | — |
| | — |
| | 149 |
| | — |
| | 149 |
| | — |
| | — |
| | 149 |
|
Other(c) | — |
| | 30 |
| | — |
| | 846 |
| | 876 |
| | — |
| | 30 |
| | — |
| | 846 |
|
| 876 |
|
| Fixed income subtotal | 2,081 |
| | 1,921 |
| | 230 |
|
| 846 |
| | 5,078 |
| | 2,081 |
| | 1,921 |
| | 230 |
| | 846 |
| | 5,078 |
|
| Middle market lending | — |
| | — |
| | 313 |
| | 367 |
| | 680 |
| | — |
| | — |
| | 313 |
| | 367 |
| | 680 |
|
| Private equity | — |
| | — |
| | — |
| | 329 |
| | 329 |
| | — |
| | — |
| | — |
| | 329 |
| | 329 |
|
| Real estate | — |
| | — |
| | — |
| | 510 |
| | 510 |
| | — |
| | — |
| | — |
| | 510 |
| | 510 |
|
NDT fund investments subtotal(d) | 5,251 |
| | 3,598 |
| | 543 |
| | 3,433 |
|
| 12,825 |
|
| 5,251 |
| | 3,598 |
| | 543 |
|
| 3,433 |
|
| 12,825 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
The Registrants did not record material interest and penalty expense related to tax positions reflected in their Consolidated Balance Sheets. Interest expense and penalty expense are recorded in Interest expense, net and Other, net, respectively, in Other income and deductions in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
Description of tax years open to assessment by major jurisdiction
| | | | | | | | | | | |
| Major Jurisdiction | Open Years | | Registrants Impacted |
Federal consolidated income tax returns(a) | 2010-2019 | | All Registrants |
| Delaware separate corporate income tax returns | Same as federal | | DPL |
| District of Columbia combined corporate income tax returns | 2017-2019 | | Exelon, PHI, Pepco |
| Illinois unitary corporate income tax returns | 2012-2019 | | Exelon, Generation, ComEd |
| Maryland separate company corporate net income tax returns | Same as federal | | BGE, Pepco, DPL |
| New Jersey separate corporate income tax returns | 2013-2019 | | Exelon, Generation |
| New Jersey separate corporate income tax returns | 2014-2019 | | ACE |
| New York combined corporate income tax returns | 2010-March 2012 | | Exelon, Generation |
| New York combined corporate income tax returns | 2011-2019 | | Exelon, Generation |
| Pennsylvania separate corporate income tax returns | 2011-2019 | | Exelon, Generation |
| Pennsylvania separate corporate income tax returns | 2017-2019 | | PECO |
__________
(a)Certain registrants are only open to assessment for tax years since joining the Exelon federal consolidated group; BGE beginning in 2012 and PHI, Pepco, DPL, and ACE beginning in 2016.
Other Tax Matters
Long-Term Marginal State Income Tax Rate (All Registrants)
Quarterly, Exelon reviews and updates its marginal state income tax rates for changes in state apportionment. The Registrants remeasure their existing deferred income tax balances to reflect the changes in marginal rates, which results in either an increase or a decrease to their net deferred income tax liability balances. Utility Registrants record corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts. The impacts to the Utility Registrants for the years ended December 31, 2020, 2019, and 2018 were not material.
| | | | | | | | | | | | | | | |
| December 31, 2020 | Exelon | | Generation | | | | |
| Increase (decrease) to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes | $ | 66 | | | $ | (26) | | | | | |
| | | | | | | |
| December 31, 2019 | | | | | | | |
| Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes | $ | 23 | | | $ | 9 | | | | | |
| | | | | | | |
| December 31, 2018 | | | | | | | |
| Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes | $ | (50) | | | $ | (53) | | | | | |
| | | | | | | |
Allocation of Tax Benefits (All Registrants)
Generation and the Utility Registrants are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net federal and state benefits attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit.
The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | Exelon |
| As of December 31, 2018 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Pledged assets for Zion Station decommissioning |
| |
| |
| | | |
| |
| |
| |
| | | |
|
| Cash equivalents | 9 |
| | — |
| | — |
| | — |
| | 9 |
| | 9 |
| | — |
| | — |
| | — |
| | 9 |
|
| Equities | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Middle market lending | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Pledged assets for Zion Station decommissioning subtotal | 9 |
| | — |
| | — |
|
| — |
|
| 9 |
|
| 9 |
| | — |
| | — |
|
| — |
|
| 9 |
|
| Rabbi trust investments |
| |
| |
| | | |
| |
| |
| |
| | | |
|
| Cash equivalents | 5 |
| | — |
| | — |
| | — |
| | 5 |
| | 48 |
| | — |
| | — |
| | — |
| | 48 |
|
| Mutual funds | 24 |
| | — |
| | — |
| | — |
| | 24 |
| | 72 |
| | — |
| | — |
| | — |
| | 72 |
|
| Fixed income | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 15 |
| | — |
| | — |
| | 15 |
|
| Life insurance contracts | — |
| | 22 |
| | — |
| | — |
| | 22 |
| | — |
| | 70 |
| | 38 |
| | — |
| | 108 |
|
Rabbi trust investments subtotal(f) | 29 |
| | 22 |
| | — |
| | — |
|
| 51 |
|
| 120 |
| | 85 |
| | 38 |
| | — |
|
| 243 |
|
| Commodity derivative assets |
| |
| |
| | | |
|
| |
| |
| |
| | | |
|
|
| Economic hedges | 541 |
| | 2,760 |
| | 1,470 |
| | — |
| | 4,771 |
| | 541 |
| | 2,760 |
| | 1,470 |
| | — |
| | 4,771 |
|
| Proprietary trading | — |
| | 69 |
| | 77 |
| | — |
| | 146 |
| | — |
| | 69 |
| | 77 |
| | — |
| | 146 |
|
Effect of netting and allocation of
collateral(e) | (582 | ) | | (2,357 | ) | | (732 | ) | | — |
| | (3,671 | ) | | (582 | ) | | (2,357 | ) | | (732 | ) | | — |
| | (3,671 | ) |
| Commodity derivative assets subtotal | (41 | ) | | 472 |
| | 815 |
|
| — |
|
| 1,246 |
|
| (41 | ) | | 472 |
| | 815 |
|
| — |
|
| 1,246 |
|
| Interest rate and foreign currency derivative assets | | | | | | | | | | | | | | | | | | | |
| Derivatives designated as hedging instruments | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Economic hedges | — |
| | 13 |
| | — |
| | — |
| | 13 |
| | — |
| | 13 |
| | — |
| | — |
| | 13 |
|
| Effect of netting and allocation of collateral | — |
| | (3 | ) | | — |
| | — |
| | (3 | ) | | — |
| | (3 | ) | | — |
| | — |
| | (3 | ) |
| Interest rate and foreign currency derivative assets subtotal | — |
| | 10 |
| | — |
|
| — |
|
| 10 |
|
| — |
| | 10 |
| | — |
|
| — |
|
| 10 |
|
| Other investments | — |
| | — |
| | 42 |
| | — |
| | 42 |
| | — |
| | — |
| | 42 |
| | — |
| | 42 |
|
| Total assets | 5,829 |
| | 4,102 |
| | 1,400 |
|
| 3,433 |
|
| 14,764 |
|
| 6,582 |
| | 4,165 |
| | 1,438 |
|
| 3,433 |
|
| 15,618 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
December 31, 2020(a) | $ | 64 | | | $ | 14 | | | $ | 17 | | | $ | 0 | | | $ | 17 | | | $ | 8 | | | $ | 6 | | | $ | 1 | |
December 31, 2019(b) | 41 | | | 0 | | | 14 | | | 3 | | | 7 | | | 6 | | | 1 | | | 0 | |
December 31, 2018(c) | 155 | | | 1 | | | 48 | | | 26 | | | 2 | | | 0 | | | 0 | | | 0 | |
__________
(a)BGE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
(b)ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
(c)Pepco, DPL, and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
Research and Development Activities
In the fourth quarter of 2019, Exelon and Generation recognized additional tax benefits related to certain research and development activities that qualify for federal and state tax incentives for the 2010 through 2018 tax years, which resulted in an increase to Exelon’s and Generation’s net income of $108 million and $75 million, respectively, for the year ended December 31, 2019, reflecting a decrease to Exelon’s and Generation’s Income tax expense of $97 million and $66 million, respectively.
15. Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and OPEB plans for essentially all current employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018 for most newly-hired Generation and BSC non-represented, non-craft, employees and January 1, 2021 for most newly-hired utility management employees, these newly-hired employees are not eligible for pension benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits. Effective January 1, 2021, most non-represented, non-craft, employees who are under the age of 40 are not eligible for retiree health care benefits.
Effective January 1, 2019, Exelon merged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans did not change the benefits offered to the plan participants and, thus, had no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP are amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | Exelon |
| As of December 31, 2018 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Liabilities |
| |
| |
| | | |
| |
| |
| |
| | | |
|
|
| Commodity derivative liabilities |
| |
| |
| | | |
| |
| |
| |
| | | |
|
| Economic hedges | (642 | ) | | (2,963 | ) | | (1,027 | ) | | — |
| | (4,632 | ) | | (642 | ) | | (2,963 | ) | | (1,276 | ) | | — |
| | (4,881 | ) |
| Proprietary trading | — |
| | (73 | ) | | (21 | ) | | — |
| | (94 | ) | | — |
| | (73 | ) | | (21 | ) | | — |
| | (94 | ) |
Effect of netting and allocation of
collateral(e) | 639 |
| | 2,581 |
| | 808 |
| | — |
| | 4,028 |
| | 639 |
| | 2,581 |
| | 808 |
| | — |
| | 4,028 |
|
| Commodity derivative liabilities subtotal | (3 | ) | | (455 | ) | | (240 | ) |
| — |
|
| (698 | ) |
| (3 | ) | | (455 | ) | | (489 | ) |
| — |
|
| (947 | ) |
| Interest rate and foreign currency derivative liabilities | | | | | | | | | | | | | | | | | | | |
| Derivatives designated as hedging instruments | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (4 | ) | | — |
| | — |
| | (4 | ) |
| Economic hedges | — |
| | (6 | ) | | — |
| | — |
| | (6 | ) | | — |
| | (6 | ) | | — |
| | — |
| | (6 | ) |
| Effect of netting and allocation of collateral | — |
| | 3 |
| | — |
| | — |
| | 3 |
| | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Interest rate and foreign currency derivative liabilities subtotal | — |
| | (3 | ) | | — |
|
| — |
|
| (3 | ) |
| — |
| | (7 | ) | | — |
|
| — |
|
| (7 | ) |
| Deferred compensation obligation | — |
| | (35 | ) | | — |
| | — |
| | (35 | ) | | — |
| | (137 | ) | | — |
| | — |
| | (137 | ) |
| Total liabilities | (3 | ) | | (493 | ) | | (240 | ) |
| — |
|
| (736 | ) |
| (3 | ) | | (599 | ) | | (489 | ) |
| — |
|
| (1,091 | ) |
| Total net assets | $ | 5,826 |
| | $ | 3,609 |
| | $ | 1,160 |
|
| $ | 3,433 |
|
| $ | 14,028 |
|
| $ | 6,579 |
| | $ | 3,566 |
| | $ | 949 |
|
| $ | 3,433 |
|
| $ | 14,527 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | Exelon |
| As of December 31, 2017 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Assets | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 168 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 168 |
| | $ | 656 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 656 |
|
| NDT fund investments | | | | | | | | |
| | | | | | | | | |
|
Cash equivalents(b) | 135 |
| | 85 |
| | — |
| | — |
| | 220 |
| | 135 |
| | 85 |
| | — |
| | — |
| | 220 |
|
| Equities | 4,163 |
| | 915 |
| | — |
| | 2,176 |
| | 7,254 |
| | 4,163 |
| | 915 |
| | — |
| | 2,176 |
| | 7,254 |
|
| Fixed income |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
| Corporate debt | — |
| | 1,614 |
| | 251 |
| | — |
| | 1,865 |
| | — |
| | 1,614 |
| | 251 |
| | — |
| | 1,865 |
|
| U.S. Treasury and agencies | 1,917 |
| | 52 |
| | — |
| | — |
| | 1,969 |
| | 1,917 |
| | 52 |
| | — |
| | — |
| | 1,969 |
|
| Foreign governments | — |
| | 82 |
| | — |
| | — |
| | 82 |
| | — |
| | 82 |
| | — |
| | — |
| | 82 |
|
| State and municipal debt | — |
| | 263 |
| | — |
| | — |
| | 263 |
| | — |
| | 263 |
| | — |
| | — |
| | 263 |
|
Other(c) | — |
| | 47 |
| | — |
| | 510 |
| | 557 |
| | — |
| | 47 |
| | — |
| | 510 |
| | 557 |
|
| Fixed income subtotal | 1,917 |
|
| 2,058 |
|
| 251 |
|
| 510 |
|
| 4,736 |
|
| 1,917 |
|
| 2,058 |
|
| 251 |
|
| 510 |
|
| 4,736 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
The table below shows the pension and OPEB plans in which employees of each operating company participated at December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Operating Company(e) |
| Name of Plan: | | | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Qualified Pension Plans: | | | | | | | | | | | | | | | | | | |
Exelon Corporation Retirement Program(a) | | | | X | | X | | X | | X | | X | | X | | X | | X |
Exelon Corporation Pension Plan for Bargaining Unit Employees(a) | | | | X | | X | | | | | | | | | | | | |
Exelon New England Union Employees Pension Plan(a) | | | | X | | | | | | | | | | | | | | |
Exelon Employee Pension Plan for Clinton, TMI, and Oyster Creek(a) | | | | X | | X | | X | | X | | X | | | | | | X |
Pension Plan of Constellation Energy Group, Inc.(b) | | | | X | | X | | X | | X | | X | | X | | X | | |
Pension Plan of Constellation Energy Nuclear Group, LLC(c) | | | | X | | X | | | | X | | X | | X | | | | |
Nine Mile Point Pension Plan(c) | | | | X | | | | | | | | | | | | | | |
Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B(b) | | | | X | | | | | | | | | | | | | | |
Pepco Holdings LLC Retirement Plan(d) | | | | X | | X | | X | | X | | X | | X | | X | | X |
| Non-Qualified Pension Plans: | | | | | | | | | | | | | | | | | | |
Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan(a) | | | | X | | X | | X | | | | X | | | | | | |
Exelon Corporation Supplemental Management Retirement Plan(a) | | | | X | | X | | X | | X | | X | | X | | | | X |
Constellation Energy Group, Inc. Senior Executive Supplemental Plan(b) | | | | X | | | | | | X | | X | | | | | | |
Constellation Energy Group, Inc. Supplemental Pension Plan(b) | | | | X | | | | | | X | | X | | | | | | |
Constellation Energy Group, Inc. Benefits Restoration Plan(b) | | | | X | | X | | | | X | | X | | | | | | |
Constellation Energy Nuclear Plan, LLC Executive Retirement Plan(c) | | | | X | | | | | | | | X | | | | | | |
Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan(c) | | | | X | | | | | | | | X | | | | | | |
Baltimore Gas & Electric Company Executive Benefit Plan(b) | | | | X | | | | | | X | | | | | | | | |
Baltimore Gas & Electric Company Manager Benefit Plan(b) | | | | X | | X | | | | X | | | | | | | | |
Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan(d) | | | | X | | | | | | | | X | | X | | X | | X |
Conectiv Supplemental Executive Retirement Plan(d) | | | | X | | | | | | | | X | | | | X | | X |
Pepco Holdings LLC Combined Executive Retirement Plan(d) | | | | | | | | | | | | X | | X | | | | |
Atlantic City Electric Director Retirement Plan(d) | | | | | | | | | | | | | | | | | | X |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | Exelon |
| As of December 31, 2017 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Middle market lending | — |
| | — |
| | 397 |
| | 131 |
| | 528 |
| | — |
| | — |
| | 397 |
| | 131 |
| | 528 |
|
| Private equity | — |
| | — |
| | — |
| | 222 |
| | 222 |
| | — |
| | — |
| | — |
| | 222 |
| | 222 |
|
| Real estate | — |
| | — |
| | — |
| | 471 |
| | 471 |
| | — |
| | — |
| | — |
| | 471 |
| | 471 |
|
NDT fund investments subtotal(d) | 6,215 |
|
| 3,058 |
|
| 648 |
|
| 3,510 |
|
| 13,431 |
|
| 6,215 |
|
| 3,058 |
|
| 648 |
|
| 3,510 |
|
| 13,431 |
|
| Pledged assets for Zion Station decommissioning |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
| Cash equivalents | 2 |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
| Equities | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Middle market lending | — |
|
| — |
|
| 12 |
| | 24 |
| | 36 |
| | — |
|
| — |
|
| 12 |
| | 24 |
| | 36 |
|
| Pledged assets for Zion Station decommissioning subtotal | 2 |
|
| 1 |
|
| 12 |
|
| 24 |
|
| 39 |
|
| 2 |
|
| 1 |
|
| 12 |
|
| 24 |
|
| 39 |
|
| Rabbi trust investments |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
| Cash equivalents | 5 |
| | — |
| | — |
| | — |
| | 5 |
| | 77 |
| | — |
| | — |
| | — |
| | 77 |
|
| Mutual funds | 23 |
| | — |
| | — |
| | — |
| | 23 |
| | 58 |
| | — |
| | — |
| | — |
| | 58 |
|
| Fixed income | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | — |
| | — |
| | 12 |
|
| Life insurance contracts | — |
| | 22 |
| | — |
| | — |
| | 22 |
| | — |
| | 71 |
| | 22 |
| | — |
| | 93 |
|
Rabbi trust investments subtotal(f) | 28 |
|
| 22 |
|
| — |
|
| — |
|
| 50 |
|
| 135 |
|
| 83 |
|
| 22 |
|
| — |
|
| 240 |
|
| Commodity derivative assets | | | | | | | | | | | | | | | | | | | |
| Economic hedges | 557 |
| | 2,378 |
| | 1,290 |
| | — |
| | 4,225 |
| | 557 |
| | 2,378 |
| | 1,290 |
| | — |
| | 4,225 |
|
| Proprietary trading | 2 |
| | 31 |
| | 35 |
| | — |
| | 68 |
| | 2 |
| | 31 |
| | 35 |
| | — |
| | 68 |
|
Effect of netting and allocation of
collateral(e) | (585 | ) | | (1,769 | ) | | (635 | ) | | — |
| | (2,989 | ) | | (585 | ) | | (1,769 | ) | | (635 | ) | | — |
| | (2,989 | ) |
| Commodity derivative assets subtotal | (26 | ) |
| 640 |
|
| 690 |
|
| — |
|
| 1,304 |
|
| (26 | ) |
| 640 |
|
| 690 |
|
| — |
|
| 1,304 |
|
| Interest rate and foreign currency derivative assets | | | | | | | | | | | | | | | | | | | |
| Derivatives designated as hedging instruments | — |
| | 3 |
| | — |
| | — |
| | 3 |
| | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
| Economic hedges | — |
| | 10 |
| | — |
| | — |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
| Effect of netting and allocation of collateral | (2 | ) | | (5 | ) | | — |
| | — |
| | (7 | ) | | (2 | ) | | (5 | ) | | — |
| | — |
| | (7 | ) |
| Interest rate and foreign currency derivative assets subtotal | (2 | ) |
| 8 |
|
| — |
|
| — |
|
| 6 |
|
| (2 | ) |
| 11 |
|
| — |
|
| — |
|
| 9 |
|
| Other investments | — |
|
| — |
|
| 37 |
| | — |
| | 37 |
| | — |
| | — |
| | 37 |
| | — |
| | 37 |
|
| Total assets | 6,385 |
|
| 3,729 |
|
| 1,387 |
|
| 3,534 |
|
| 15,035 |
|
| 6,980 |
|
| 3,793 |
|
| 1,409 |
|
| 3,534 |
|
| 15,716 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | Exelon |
| As of December 31, 2017 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Liabilities |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
|
| Commodity derivative liabilities |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
| Economic hedges | (712 | ) | | (2,226 | ) | | (845 | ) | | — |
| | (3,783 | ) | | (713 | ) | | (2,226 | ) | | (1,101 | ) | | — |
| | (4,040 | ) |
| Proprietary trading | (2 | ) | | (42 | ) | | (9 | ) | | — |
| | (53 | ) | | (2 | ) | | (42 | ) | | (9 | ) | | — |
| | (53 | ) |
Effect of netting and allocation of
collateral(e) | 650 |
| | 2,089 |
| | 716 |
| | — |
| | 3,455 |
| | 651 |
| | 2,089 |
| | 716 |
| | — |
| | 3,456 |
|
| Commodity derivative liabilities subtotal | (64 | ) |
| (179 | ) |
| (138 | ) |
| — |
|
| (381 | ) |
| (64 | ) |
| (179 | ) |
| (394 | ) |
| — |
|
| (637 | ) |
| Interest rate and foreign currency derivative liabilities | | | | | | | | | | | | | | | | | | | |
| Derivatives designated as hedging instruments | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) |
| Economic hedges | (1 | ) | | (8 | ) | | — |
| | — |
| | (9 | ) | | (1 | ) | | (8 | ) | | — |
| | — |
| | (9 | ) |
| Effect of netting and allocation of collateral | 2 |
| | 5 |
| | — |
| | — |
| | 7 |
| | 2 |
| | 5 |
| | — |
| | — |
| | 7 |
|
| Interest rate and foreign currency derivative liabilities subtotal | 1 |
|
| (5 | ) |
| — |
|
| — |
|
| (4 | ) |
| 1 |
|
| (5 | ) |
| — |
|
| — |
|
| (4 | ) |
| Deferred compensation obligation | — |
|
| (38 | ) |
| — |
| | — |
| | (38 | ) | | — |
|
| (145 | ) |
| — |
| | — |
| | (145 | ) |
| Total liabilities | (63 | ) |
| (222 | ) |
| (138 | ) |
| — |
|
| (423 | ) |
| (63 | ) |
| (329 | ) |
| (394 | ) |
| — |
|
| (786 | ) |
| Total net assets | $ | 6,322 |
|
| $ | 3,507 |
|
| $ | 1,249 |
|
| $ | 3,534 |
|
| $ | 14,612 |
|
| $ | 6,917 |
|
| $ | 3,464 |
|
| $ | 1,015 |
|
| $ | 3,534 |
|
| $ | 14,930 |
|
__________
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(a) | Generation excludes cash | | | Operating Company(e) |
Name of $283 million and $259 million at December 31, 2018 and 2017 and restricted cash of $39 million and $127 million at December 31, 2018 and 2017. Exelon excludes cash of $458 million and $389 million at December 31, 2018 and 2017 and restricted cash of $80 million and $145 million at December 31, 2018 and 2017 and includes long-term restricted cash of $185 million and $85 million at December 31, 2018 and 2017, which is reported in Other deferred debits in the Consolidated Balance Sheets.Plan: | | | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| OPEB Plans: | | | | | | | | | | | | | | | | | | |
(b)PECO Energy Company Retiree Medical Plan(a) | Includes $50 million and $77 million of cash received from outstanding repurchase agreements at December 31, 2018 and 2017, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below. | | | X | | X | | X | | X | | X | | X | | X | | X |
Exelon Corporation Health Care Program(a) | | | | X | | X | | X | | X | | X | | X | | | | X |
Exelon Corporation Employees’ Life Insurance Plan(a) | | | | X | | X | | X | | X | | | | | | | | |
(c)Exelon Corporation Health Reimbursement Arrangement Plan(a) | Includes derivative instruments of $44 million and less than $1 million, which have a total notional amount of $1,432 million and $811 million at December 31, 2018 and 2017, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss. |
| | X | | X | | X | | X | | | | | | | | |
(d)Constellation Energy Group, Inc. Retiree Medical Plan(b) | Excludes net liabilities of $130 million and $82 million at December 31, 2018 and 2017, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less. |
| | X | | X | | X | | X | | X | | X | | | | |
(e)Constellation Energy Group, Inc. Retiree Dental Plan(b) | Excludes net assets of less than $1 million at December 31, 2018 and 2017. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. |
| | X | | | | | | X | | | | | | | | |
(f)Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan(b) | The amount of unrealized gains/(losses) at Generation totaled less than $1 million and $1 million for the years ended December 31, 2018 and 2017, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million for the years ended December 31, 2018 and 2017, respectively. |
| | X | | X | | X | | X | | X | | X | | | | |
(g)Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan(b) | Collateral posted/(received) from counterparties totaled $57 million, $224 million and $76 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2018. Collateral posted/(received) from counterparties totaled $65 million, $320 million and $81 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2017. |
| | X | | | | | | X | | | | | | | | |
(h)Exelon New England Union Post-Employment Medical Savings Account Plan(a) | Of the collateral posted/(received), $(94) million | | | X | | | | | | | | | | | | | | |
Retiree Medical Plan of Constellation Energy Nuclear Group, LLC(c) | | | | X | | X | | | | X | | | | X | | | | |
Retiree Dental Plan of Constellation Energy Nuclear Group, LLC(c) | | | | X | | X | | | | X | | | | X | | | | |
Nine Mile Point Nuclear Station, LLC Medical Care and $(117) million represents variation margin on the exchanges as of December 31, 2018 and 2017, respectively.Prescription Drug Plan for Retired Employees(c) | | | | X | | | | | | | | | | | | | | |
Pepco Holdings LLC Welfare Plan for Retirees(d) | | | | X | | X | | X | | X | | X | | X | | X | | X |
__________
(a)These plans are collectively referred to as the legacy Exelon plans.
(b)These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans.
(c)These plans are collectively referred to as the legacy CENG plans.
(d)These plans are collectively referred to as the legacy PHI plans.
(e)Employees generally remain in their legacy benefit plans when transferring between operating companies.
Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Exelon has elected that the trusts underlying these plans be treated as qualified trusts under the IRC. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations.
Benefit Obligations, Plan Assets, and Funded Status
During the first quarter of 2020, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2020. This valuation resulted in an increase to the pension and OPEB obligations of $8 million and $31 million, respectively. Additionally, accumulated other comprehensive loss increased by $7 million (after-tax) and regulatory assets and liabilities increased by $19 million and decreased by $10 million, respectively.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $72 millionas of December 31, 2018. Changes were immaterial in fair value, cumulative adjustments and impairments for the year ended December 31, 2018.
ComEd, PECO and BGE
The following tables presentprovide a rollforward of the changes in the benefit obligations and plan assets of Exelon for the most recent two years for all plans combined:
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2020 | | 2019 |
| Change in benefit obligation: | | | | | | | |
| Net benefit obligation at beginning of year | $ | 22,868 | | | $ | 20,692 | | | $ | 4,658 | | | $ | 4,369 | |
| Service cost | 387 | | | 357 | | | 90 | | | 93 | |
| Interest cost | 757 | | | 883 | | | 154 | | | 188 | |
| Plan participants’ contributions | 0 | | | 0 | | | 49 | | | 44 | |
Actuarial loss(a) | 2,217 | | | 2,322 | | | 49 | | | 250 | |
| Plan amendments | 0 | | | 68 | | | (111) | | | 0 | |
| | | | | | | |
| Curtailments | 0 | | | (3) | | | 0 | | | 0 | |
| Settlements | (45) | | | (35) | | | (5) | | | (4) | |
| Contractual termination benefits | 0 | | | 1 | | | 0 | | | 0 | |
| Gross benefits paid | (1,290) | | | (1,417) | | | (280) | | | (282) | |
| Net benefit obligation at end of year | $ | 24,894 | | | $ | 22,868 | | | $ | 4,604 | | | $ | 4,658 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2020 | | 2019 |
| Change in plan assets: | | | | | | | |
| Fair value of net plan assets at beginning of year | $ | 18,590 | | | $ | 16,678 | | | $ | 2,541 | | | $ | 2,408 | |
| Actual return on plan assets | 2,547 | | | 3,008 | | | 190 | | | 324 | |
| Employer contributions | 542 | | | 356 | | | 59 | | | 51 | |
| Plan participants’ contributions | 0 | | | 0 | | | 49 | | | 44 | |
| Gross benefits paid | (1,290) | | | (1,417) | | | (280) | | | (282) | |
| | | | | | | |
| Settlements | (45) | | | (35) | | | (5) | | | (4) | |
| Fair value of net plan assets at end of year | $ | 20,344 | | | $ | 18,590 | | | $ | 2,554 | | | $ | 2,541 | |
__________
(a)The pension and liabilities measuredOPEB actuarial losses in 2020 and recorded at2019 primarily reflect a decrease in the discount rate. OPEB losses in 2020 were offset by gains related to plan changes.
Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2020 | | 2019 |
| Other current liabilities | $ | 47 | | | $ | 31 | | | $ | 42 | | | $ | 41 | |
| Pension obligations | 4,503 | | | 4,247 | | | 0 | | | 0 | |
| Non-pension postretirement benefit obligations | 0 | | | 0 | | | 2,008 | | | 2,076 | |
| Unfunded status (net benefit obligation less plan assets) | $ | 4,550 | | | $ | 4,278 | | | $ | 2,050 | | | $ | 2,117 | |
The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in ComEd's, PECO'sexcess of plan assets. Information for pension and BGE's Consolidated Balance Sheets on a recurring basisOPEB plans with projected benefit obligations (PBO) and their level withinaccumulated postretirement benefit obligation (APBO), respectively, in excess of plan assets has been disclosed in the fair value hierarchyObligations and Plan Assets table above as of December 31, 2018all pension and 2017:OPEB plans are underfunded.
| | | | | | | | | | | | | |
| ABO in excess of plan assets | Exelon | | |
| 2020 | | 2019 | | |
| | | | | |
| ABO | $ | 23,514 | | | $ | 21,727 | | | |
| Fair value of net plan assets | 20,344 | | | 18,590 | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | ComEd | | PECO | | BGE |
| As of December 31, 2018 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 209 |
|
| $ | — |
|
| $ | — |
| | $ | 209 |
| | $ | 111 |
|
| $ | — |
|
| $ | — |
| | $ | 111 |
| | $ | 4 |
|
| $ | — |
|
| $ | — |
| | $ | 4 |
|
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | |
| Mutual funds | — |
|
| — |
|
| — |
| | — |
| | 7 |
|
| — |
|
| — |
| | 7 |
| | 6 |
|
| — |
|
| — |
| | 6 |
|
| Life insurance contracts | — |
| | — |
| | — |
| | — |
| | — |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
|
Rabbi trust investments subtotal(b) | — |
| | — |
| | — |
| | — |
| | 7 |
| | 10 |
| | — |
| | 17 |
| | 6 |
| | — |
| | — |
| | 6 |
|
| Total assets | 209 |
|
| — |
|
| — |
|
| 209 |
|
| 118 |
|
| 10 |
|
| — |
|
| 128 |
|
| 10 |
|
| — |
|
| — |
|
| 10 |
|
| Liabilities |
|
|
|
|
| |
| |
|
|
|
|
| |
| |
|
|
|
|
| |
|
| Deferred compensation obligation | — |
|
| (6 | ) |
| — |
| | (6 | ) | | — |
|
| (10 | ) |
| — |
| | (10 | ) | | — |
|
| (5 | ) |
| — |
| | (5 | ) |
Mark-to-market derivative liabilities(c) | — |
|
| — |
|
| (249 | ) | | (249 | ) | | — |
|
| — |
|
| — |
| | — |
| | — |
|
| — |
|
| — |
| | — |
|
| Total liabilities | — |
|
| (6 | ) |
| (249 | ) |
| (255 | ) |
| — |
|
| (10 | ) |
| — |
|
| (10 | ) |
| — |
|
| (5 | ) |
| — |
|
| (5 | ) |
| Total net assets (liabilities) | $ | 209 |
|
| $ | (6 | ) |
| $ | (249 | ) |
| $ | (46 | ) |
| $ | 118 |
|
| $ | — |
|
| $ | — |
|
| $ | 118 |
|
| $ | 10 |
|
| $ | (5 | ) |
| $ | — |
|
| $ | 5 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Components of Net Periodic Benefit Costs
The majority of the 2020 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.34%. The majority of the 2020 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.69% for funded plans and a discount rate of 3.31%.
A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2020, 2019, and 2018.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 |
| Components of net periodic benefit cost: | | | | | | | | | | | |
| Service cost | $ | 387 | | | $ | 357 | | | $ | 405 | | | $ | 90 | | | $ | 93 | | | $ | 112 | |
| Interest cost | 757 | | | 883 | | | 802 | | | 154 | | | 188 | | | 175 | |
| Expected return on assets | (1,270) | | | (1,225) | | | (1,252) | | | (163) | | | (153) | | | (173) | |
| Amortization of: | | | | | | | | | | | |
| | | | | | | | | | | |
| Prior service cost (credit) | 4 | | | 0 | | | 2 | | | (124) | | | (179) | | | (186) | |
| Actuarial loss | 512 | | | 414 | | | 629 | | | 49 | | | 45 | | | 66 | |
| Curtailment benefits | 0 | | | 0 | | | 0 | | | (1) | | | 0 | | | 0 | |
| Settlement and other charges | 14 | | | 17 | | | 3 | | | 1 | | | 1 | | | 1 | |
| Contractual termination benefits | 0 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Net periodic benefit cost | $ | 404 | | | $ | 447 | | | $ | 589 | | | $ | 6 | | | $ | (5) | | | $ | (5) | |
Cost Allocation to Exelon Subsidiaries
All Registrants account for their participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocates costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan.
The amounts below represent the Registrants' allocated pension and OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For Generation and the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2020 | $ | 411 | | | $ | 115 | | | $ | 114 | | | $ | 5 | | | $ | 64 | | | $ | 70 | | | $ | 15 | | | $ | 7 | | | $ | 14 | |
| 2019 | 442 | | | 135 | | | 96 | | | 12 | | | 61 | | | 95 | | | 25 | | | 15 | | | 16 | |
| 2018 | 583 | | | 204 | | | 177 | | | 18 | | | 60 | | | 67 | | | 15 | | | 6 | | | 12 | |
Components of AOCI and Regulatory Assets
Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its balance sheet, with offsetting entries to AOCI and regulatory assets (liabilities). A portion of current year actuarial (gains) losses and prior service costs (credits) is capitalized within Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets (liabilities) for Exelon for the years ended December 31, 2020, 2019, and 2018 for all plans combined.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | ComEd | | PECO | | BGE |
| As of December 31, 2017 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 98 |
|
| $ | — |
|
| $ | — |
| | $ | 98 |
| | $ | 228 |
|
| $ | — |
|
| $ | — |
| | $ | 228 |
| | $ | — |
|
| $ | — |
|
| $ | — |
| | $ | — |
|
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | |
| Mutual funds | — |
|
| — |
|
| — |
| | — |
| | 7 |
|
| — |
|
| — |
| | 7 |
| | 6 |
|
| — |
|
| — |
| | 6 |
|
| Life insurance contracts | — |
| | — |
| | — |
| | — |
| | — |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
|
Rabbi trust investments subtotal(b) | — |
| | — |
| | — |
| | — |
| | 7 |
| | 10 |
| | — |
| | 17 |
| | 6 |
| | — |
| | — |
| | 6 |
|
| Total assets | 98 |
|
| — |
|
| — |
|
| 98 |
|
| 235 |
|
| 10 |
|
| — |
|
| 245 |
|
| 6 |
|
| — |
|
| — |
|
| 6 |
|
| Liabilities |
|
|
|
|
| |
| |
|
|
|
|
| |
| |
|
|
|
|
| |
|
| Deferred compensation obligation | — |
|
| (8 | ) |
| — |
| | (8 | ) | | — |
|
| (11 | ) |
| — |
| | (11 | ) | | — |
|
| (5 | ) |
| — |
| | (5 | ) |
Mark-to-market derivative liabilities(c) | — |
|
| — |
|
| (256 | ) | | (256 | ) | | — |
|
| — |
|
| — |
| | — |
| | — |
|
| — |
|
| — |
| | — |
|
| Total liabilities | — |
|
| (8 | ) |
| (256 | ) |
| (264 | ) |
| — |
|
| (11 | ) |
| — |
|
| (11 | ) |
| — |
|
| (5 | ) |
| — |
|
| (5 | ) |
| Total net assets (liabilities) | $ | 98 |
|
| $ | (8 | ) |
| $ | (256 | ) |
| $ | (166 | ) |
| $ | 235 |
|
| $ | (1 | ) |
| $ | — |
|
| $ | 234 |
|
| $ | 6 |
|
| $ | (5 | ) |
| $ | — |
|
| $ | 1 |
|
__________
| |
(a) | ComEd excludes cash of $93 million and $45 million at December 31, 2018 and 2017 and restricted cash of $28 million at December 31, 2018 and includes long-term restricted cash of $166 million and $62 million at December 31, 2018 and December 31, 2017, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $24 million and $47 million at December 31, 2018 and 2017. BGE excludes cash of $7 million and $17 million at December 31, 2018 and 2017 and restricted cash of $2 million and $1 million at December 31, 2018 and December 31, 2017.
|
| |
(b) | The amount of unrealized gains/(losses) at ComEd, PECO and BGE totaled less than $1 million for the years ended December 31, 2018 and December 31, 2017. |
| |
(c) | The Level 3 balance consists of the current and noncurrent liability of $26 million and $223 million, respectively, at December 31, 2018, and $21 million and $235 million, respectively, at December 31, 2017, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
PHI, Pepco, DPL and ACE | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 |
| Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities): | | | | | | | | | | | |
| Current year actuarial loss (gain) | $ | 941 | | | $ | 538 | | | $ | 635 | | | $ | 22 | | | $ | 80 | | | $ | (232) | |
| Amortization of actuarial loss | (512) | | | (414) | | | (629) | | | (49) | | | (45) | | | (66) | |
| Current year prior service cost (credit) | 0 | | | 68 | | | (4) | | | (111) | | | 0 | | | 0 | |
| Amortization of prior service (cost) credit | (4) | | | 0 | | | (2) | | | 124 | | | 179 | | | 186 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Curtailments | 0 | | | (3) | | | 0 | | | 1 | | | 0 | | | 0 | |
| Settlements | (14) | | | (17) | | | (3) | | | (1) | | | (1) | | | 0 | |
| | | | | | | | | | | |
| Total recognized in AOCI and regulatory assets (liabilities) | $ | 411 | | | $ | 172 | | | $ | (3) | | | $ | (14) | | | $ | 213 | | | $ | (112) | |
| | | | | | | | | | | |
| Total recognized in AOCI | $ | 271 | | | $ | 169 | | | $ | 3 | | | $ | 6 | | | $ | 107 | | | $ | (55) | |
| Total recognized in regulatory assets (liabilities) | $ | 140 | | | $ | 3 | | | $ | (6) | | | $ | (20) | | | $ | 106 | | | $ | (57) | |
The following tables presenttable provides the components of gross accumulated other comprehensive loss and regulatory assets and liabilities measured and recorded(liabilities) for Exelon that have not been recognized as components of periodic benefit cost at fair value in PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 20182020 and 2017:2019, respectively, for all plans combined:
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | |
| | Pension Benefits | | | | OPEB | | |
| 2020 | | 2019 | | | | 2020 | | 2019 | | |
| Prior service cost (credit) | $ | 35 | | | $ | 39 | | | | | $ | (145) | | | $ | (158) | | | |
| Actuarial loss | 8,077 | | | 7,662 | | | | | 538 | | | 565 | | | |
| Total | $ | 8,112 | | | $ | 7,701 | | | | | $ | 393 | | | $ | 407 | | | |
| | | | | | | | | | | |
| Total included in AOCI | $ | 4,339 | | | $ | 4,068 | | | | | $ | 183 | | | $ | 177 | | | |
| Total included in regulatory assets (liabilities) | $ | 3,773 | | | $ | 3,633 | | | | | $ | 210 | | | $ | 230 | | | |
Average Remaining Service Period
For pension benefits, Exelon amortizes its unrecognized prior service costs (credits) and certain actuarial (gains) losses, as applicable, based on participants’ average remaining service periods.
For OPEB, Exelon amortizes its unrecognized prior service costs (credits) over participants’ average remaining service period to benefit eligibility age and amortizes certain actuarial (gains) losses over participants’ average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB were as follows:
| | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| Pension plans | | 12.3 | | | 11.7 | | | 12.0 | |
| OPEB plans: | | | | | | |
| Benefit Eligibility Age | | 9.0 | | | 8.7 | | | 8.8 | |
| Expected Retirement | | 10.2 | | | 9.3 | | | 9.5 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | As of December 31, 2018 | | | As of December 31, 2017 |
| PHI | Level 1 | | Level 2 | | Level 3 | | Total | | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 147 |
| | $ | — |
| | $ | — |
| | $ | 147 |
| | | $ | 83 |
| | $ | — |
| | $ | — |
| | $ | 83 |
|
| Rabbi trust investments | | | | | | |
| | | | | | | | |
|
|
| Cash equivalents | 42 |
| | — |
| | — |
| | 42 |
| | | 72 |
| | — |
| | — |
| | 72 |
|
| Mutual Funds | 13 |
| | — |
| | — |
| | 13 |
| | | — |
| | — |
| | — |
| | — |
|
| Fixed income | — |
| | 15 |
| | — |
| | 15 |
| | | — |
| | 12 |
| | — |
| | 12 |
|
| Life insurance contracts | — |
| | 22 |
| | 38 |
| | 60 |
| | | — |
| | 23 |
| | 22 |
| | 45 |
|
Rabbi trust investments subtotal(b) | 55 |
|
| 37 |
|
| 38 |
|
| 130 |
|
| | 72 |
|
| 35 |
|
| 22 |
|
| 129 |
|
| Total assets | 202 |
|
| 37 |
|
| 38 |
|
| 277 |
|
|
| 155 |
|
| 35 |
|
| 22 |
|
| 212 |
|
| Liabilities | | | | | | | | | | | | | | | |
|
|
| Deferred compensation obligation | — |
| | (21 | ) | | — |
| | (21 | ) | | | — |
| | (25 | ) | | — |
| | (25 | ) |
| Mark-to-market derivative liabilities | — |
| | — |
| | — |
| | — |
| | | (1 | ) | | — |
| | — |
| | (1 | ) |
| Effect of netting and allocation of collateral | — |
| | — |
| | — |
| | — |
| | | 1 |
| | — |
| | — |
| | 1 |
|
| Mark-to-market derivative liabilities subtotal | — |
|
| — |
|
| — |
|
| — |
|
|
| — |
|
| — |
|
| — |
|
| — |
|
| Total liabilities | — |
|
| (21 | ) |
| — |
|
| (21 | ) |
|
| — |
|
| (25 | ) |
| — |
|
| (25 | ) |
| Total net assets | $ | 202 |
|
| $ | 16 |
|
| $ | 38 |
|
| $ | 256 |
|
|
| $ | 155 |
|
| $ | 10 |
|
| $ | 22 |
|
| $ | 187 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pepco | | DPL | | ACE |
| As of December 31, 2018 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 38 |
| | $ | — |
| | $ | — |
| | $ | 38 |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 16 |
| | $ | 23 |
| | $ | — |
| | $ | — |
| | $ | 23 |
|
| Rabbi trust investments | | | | | | |
|
| | | | | | | |
|
| | | | | | | |
|
|
| Cash equivalents | 41 |
| | — |
| | — |
| | 41 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Fixed income | — |
| | 5 |
| | — |
| | 5 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Life insurance contracts | — |
| | 22 |
| | 37 |
| | 59 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Rabbi trust investments subtotal(b) | 41 |
|
| 27 |
|
| 37 |
|
| 105 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| Total assets | 79 |
|
| 27 |
|
| 37 |
|
| 143 |
|
| 16 |
|
| — |
|
| — |
|
| 16 |
|
| 23 |
|
| — |
|
| — |
|
| 23 |
|
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred compensation obligation | — |
| | (3 | ) | | — |
| | (3 | ) | | — |
| | (1 | ) | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
|
| Total liabilities | — |
|
| (3 | ) |
| — |
|
| (3 | ) |
| — |
|
| (1 | ) |
| — |
|
| (1 | ) |
| — |
|
| — |
|
| — |
|
| — |
|
| Total net assets (liabilities) | $ | 79 |
|
| $ | 24 |
|
| $ | 37 |
|
| $ | 140 |
|
| $ | 16 |
|
| $ | (1 | ) |
| $ | — |
|
| $ | 15 |
|
| $ | 23 |
|
| $ | — |
|
| $ | — |
|
| $ | 23 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pepco | | DPL | | ACE |
| As of December 31, 2017 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 36 |
| | $ | — |
| | $ | — |
| | $ | 36 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | 29 |
|
| Rabbi trust investments | | | | | | |
|
| | | | | | | |
|
| | | | | | | |
|
|
| Cash equivalents | 44 |
| | — |
| | — |
| | 44 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Fixed income | — |
| | 12 |
| | — |
| | 12 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Life insurance contracts | — |
| | 23 |
| | 22 |
| | 45 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Rabbi trust investments subtotal(b) | 44 |
|
| 35 |
|
| 22 |
|
| 101 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| Total assets | 80 |
|
| 35 |
|
| 22 |
|
| 137 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 29 |
|
| — |
|
| — |
|
| 29 |
|
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred compensation obligation | — |
| | (4 | ) | | — |
| | (4 | ) | | — |
| | (1 | ) | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
|
| Mark-to-market derivative liabilities | — |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
|
| Effect of netting and allocation of collateral | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
|
| Mark-to-market derivative liabilities subtotal | — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| Total liabilities | — |
|
| (4 | ) |
| — |
|
| (4 | ) |
| — |
|
| (1 | ) |
| — |
|
| (1 | ) |
| — |
|
| — |
|
| — |
|
| — |
|
| Total net assets (liabilities) | $ | 80 |
|
| $ | 31 |
|
| $ | 22 |
|
| $ | 133 |
|
| $ | — |
|
| $ | (1 | ) |
| $ | — |
|
| $ | (1 | ) |
| $ | 29 |
|
| $ | — |
|
| $ | — |
|
| $ | 29 |
|
The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and OPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, Exelon considers historical information as well as future expectations.
Expected Rate of Return. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.
Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. For the year endedDecember 31, 2020, Exelon’s mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2020 improvement scale adjusted to use Proxy SSA ultimate improvement rates. For the year ended December 31, 2019, Exelon's mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2019 improvement scale adjusted to a 0.75% long-term rate reached in 2035.
For Exelon, the following assumptions were used to determine the benefit obligations for the plans at December 31, 2020 and 2019. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB | |
| 2020 | | 2019 | | 2020 | | 2019 | |
| Discount rate | 2.58 | % | (a) | 3.34 | % | (a) | 2.51 | % | (a) | 3.31 | % | (a) |
| Investment crediting rate | 3.72 | % | (b) | 3.82 | % | (b) | N/A | | N/A | |
| Rate of compensation increase | 3.75 | % | | | (c) | 3.75 | % | | | (c) |
| Mortality table | Pri-2012 table with MP- 2020 improvement scale (adjusted) | | Pri-2012 table with MP- 2019 improvement scale (adjusted) | | Pri-2012 table with MP- 2020 improvement scale (adjusted) | | Pri-2012 table with MP- 2019 improvement scale (adjusted) | |
| Health care cost trend on covered charges | N/A | | N/A | | Initial and ultimate rate of 5.00% | | 5.00% with ultimate trend of 5.00% in 2017 | |
__________
| |
(a) | PHI excludes cash of $39 million and $12 million at December 31, 2018 and 2017 and includes long term restricted cash of $19 million and $23 million at December 31, 2018 and 2017 which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $15 million and $4 million at December 31, 2018 and 2017. DPL excludes cash of $8 million and $2 million at December 31, 2018 and 2017. ACE excludes cash of $7 million and $2 million at December 31, 2018 and 2017 and includes long-term restricted cash of $19 million and $23 million at December 31, 2018 and 2017 at December 31, 2018 and 2017 which is reported in Other deferred debits in the Consolidated Balance Sheets.
|
| |
(b) | The amount of unrealized gains/(losses) at PHI totaled $1 million for the years ended December 31, 2018 and 2017, respectively. The amount of unrealized gains/(losses) at Pepco totaled less than $1 million for the years ended December 31, 2018 and 2017, respectively. |
(a)The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and OPEB obligations. Certain benefit plans used individual rates, which range from 2.11% - 2.73% and 2.45% - 2.63% for pension and OPEB plans, respectively, as of December 31, 2020 and 3.02% - 3.44% and 3.27% - 3.40% for pension and OPEB plans, respectively, as of December 31, 2019.
(b)The investment crediting rate above represents a weighted average rate.
(c)3.25% through 2019 and 3.75% thereafter.
The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2020, 2019 and 2018:
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB | |
| 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 | |
| Discount rate | 3.34 | % | (a) | 4.31 | % | (a) | 3.62 | % | (a) | 3.31 | % | (a) | 4.30 | % | (a) | 3.61 | % | (a) |
| Investment crediting rate | 3.82 | % | (b) | 4.46 | % | (b) | 4.00 | % | (b) | N/A | | N/A | | N/A | |
| Expected return on plan assets | 7.00 | % | (c) | 7.00 | % | (c) | 7.00 | % | (c) | 6.69 | % | (c) | 6.67 | % | (c) | 6.60 | % | (c) |
| Rate of compensation increase | | (d) | | (d) | | (d) | | (d) | | (d) | | (d) |
| Mortality table | Pri-2012 table with MP- 2019 improvement scale (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | Pri-2012 table with MP- 2019 improvement scale (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | |
| Health care cost trend on covered charges | N/A | | N/A | | N/A | | Initial and ultimate rate of 5.00% | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.00% with ultimate trend of 5.00% in 2017 | |
__________
(a)The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and OPEB costs. Certain benefit plans used individual rates, which range from 3.02%-3.44% and 3.27%-3.40% for pension and OPEB plans, respectively, for the year ended December 31, 2020; 4.13%-4.36% and 4.27%-4.38% for pension and OPEB plans; respectively, for the year ended December 31, 2019; and 3.49%-3.65% and 3.57%-3.68% for pension and OPEB plans, respectively, for the year ended December 31, 2018.
(b)The investment crediting rate above represents a weighted average rate.
(c)Not applicable to pension and OPEB plans that do not have plan assets.
(d)3.25% through 2019 and 3.75% thereafter.
Contributions
Exelon allocates contributions related to its legacy Exelon pension and OPEB plans to its subsidiaries based on accounting cost. For legacy CEG, CENG, FitzPatrick, and PHI plans, pension and OPEB contributions are allocated to the subsidiaries based on employee participation (both active and retired). The following tables presentprovide contributions to the fair value reconciliationpension and OPEB plans:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB | |
| | 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 | |
| Exelon | $ | 542 | | | $ | 356 | | | $ | 337 | | | $ | 59 | | | $ | 51 | | | $ | 46 | | |
| Generation | 236 | | | 160 | | | 128 | | | 19 | | | 15 | | | 11 | | |
| ComEd | 143 | | | 72 | | | 38 | | | 5 | | | 5 | | | 4 | | |
| PECO | 18 | | | 27 | | | 28 | | | 0 | | | 1 | | | 0 | | |
| BGE | 56 | | | 34 | | | 40 | | | 22 | | | 14 | | | 14 | | |
| PHI | 30 | | | 10 | | | 62 | | | 9 | | | 15 | | | 12 | | |
| Pepco | 2 | | | 2 | | | 6 | | | 9 | | | 12 | | | 11 | | |
| DPL | 0 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | |
| ACE | 2 | | | 0 | | | 6 | | | 0 | | | 1 | | | 0 | | |
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of Level 3 assets2006 (the Act), management of the pension obligation, and liabilities measured at fair valueregulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on a recurringan ABO basis during the years ended December 31, 2018over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and 2017:current market conditions, which are subject to change,
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | ComEd | | PHI | | | | Exelon |
| For the year ended December 31, 2018 | NDT Fund Investments | | Pledged Assets
for Zion Station
Decommissioning | | Mark-to-Market
Derivatives | | Other
Investments | | Total Generation | | Mark-to-Market Derivatives | | Life Insurance Contracts(c) | | Eliminated in Consolidation | | Total |
| Balance as of January 1, 2018 | $ | 648 |
|
| $ | 12 |
| | $ | 552 |
|
| $ | 37 |
| | $ | 1,249 |
| | $ | (256 | ) | | $ | 22 |
| | $ | — |
| | $ | 1,015 |
|
| Total realized / unrealized gains (losses) |
|
|
| |
|
| | |
|
| | | | | | | |
|
| Included in net income | — |
|
| — |
| | (105 | ) | (a) | 3 |
| | (102 | ) | | — |
| | 4 |
| | — |
| | (98 | ) |
| Included in noncurrent payables to affiliates | (1 | ) |
| — |
| | — |
|
| — |
| | (1 | ) | | — |
| | — |
| | 1 |
| | — |
|
| Included in payable for Zion Station decommissioning | — |
|
| 7 |
| | — |
|
| — |
| | 7 |
| | — |
| | — |
| | — |
| | 7 |
|
| Included in regulatory assets/liabilities | — |
|
| — |
| | — |
| | — |
| | — |
| | 7 |
| (b) | — |
| | (1 | ) | | 6 |
|
| Change in collateral | — |
|
| — |
| | (5 | ) |
| — |
| | (5 | ) | | — |
| | — |
| | — |
| | (5 | ) |
| Purchases, sales, issuances and settlements | |
| | | |
| | |
| | | | | | | |
|
| Purchases | 36 |
|
| 1 |
| | 190 |
| (e) | 4 |
| | 231 |
| | — |
| | — |
| | — |
| | 231 |
|
| Sales | — |
|
| (20 | ) | | (4 | ) |
| — |
| | (24 | ) | | — |
| | — |
| | — |
| | (24 | ) |
| Issuances | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Settlements | (140 | ) |
| — |
| | 5 |
|
| — |
| | (135 | ) | | — |
| | 12 |
| | — |
| | (123 | ) |
| Transfers into Level 3 | — |
|
| — |
| | (22 | ) | (d) | — |
| | (22 | ) | | — |
| | — |
| | — |
| | (22 | ) |
| Transfers out of Level 3 | — |
|
| — |
| | (36 | ) | (d) | (2 | ) | | (38 | ) | | — |
| | — |
| | — |
| | (38 | ) |
| Other miscellaneous | — |
| | — |
| | — |
|
|
|
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Balance as of December 31, 2018 | $ | 543 |
|
| $ | — |
| | $ | 575 |
|
| $ | 42 |
|
| $ | 1,160 |
| | $ | (249 | ) |
| $ | 38 |
|
| $ | — |
| | $ | 949 |
|
| The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities held as of December 31, 2018 | $ | (5 | ) | | $ | — |
| | $ | 165 |
| | $ | 3 |
| | $ | 163 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 163 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Exelon’s estimated annual qualified pension contributions will be approximately $500 million in 2021. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.
While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.
The following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2021:
| | | | | | | | | | | | | | | | | |
| Qualified Pension Plans | | Non-Qualified Pension Plans | | OPEB |
| Exelon | $ | 505 | | | $ | 51 | | | $ | 75 | |
| Generation | 196 | | | 27 | | | 24 | |
| ComEd | 170 | | | 2 | | | 23 | |
| PECO | 14 | | | 1 | | | 0 | |
| BGE | 57 | | | 1 | | | 16 | |
| PHI | 29 | | | 9 | | | 7 | |
| Pepco | 1 | | | 2 | | | 6 | |
| DPL | 0 | | | 1 | | | 0 | |
| ACE | 3 | | | 0 | | | 0 | |
Estimated Future Benefit Payments
Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2020 were:
| | | | | | | | | | | |
| Pension
Benefits | | OPEB |
| 2021 | $ | 1,279 | | | $ | 257 | |
| 2022 | 1,280 | | | 259 | |
| 2023 | 1,315 | | | 261 | |
| 2024 | 1,325 | | | 262 | |
| 2025 | 1,338 | | | 265 | |
| 2026 through 2030 | 6,759 | | | 1,320 | |
| Total estimated future benefit payments through 2030 | $ | 13,296 | | | $ | 2,624 | |
Plan Assets
Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.
Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon’s OPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.
Actual asset returns have an impact on the costs reported for the Exelon-sponsored pension and OPEB plans. The actual asset returns across Exelon’s pension and OPEB plans for the year ended December 31, 2020 were 14.45% and 9.14%, respectively, compared to an expected long-term return assumption of 7.00% and 6.69%,
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | ComEd | | PHI | | | | Exelon |
| For the year ended December 31, 2017 | NDT Fund Investments | | Pledged Assets for Zion Station Decommissioning | | Mark-to-Market Derivatives | | Other Investments | | Total Generation | | Mark-to-Market Derivatives | | Life Insurance Contracts(c) | | Eliminated in Consolidation | | Total |
| Balance as of January 1, 2017 | $ | 677 |
|
| $ | 19 |
| | $ | 493 |
|
| $ | 42 |
| | $ | 1,231 |
| | $ | (258 | ) | | $ | 20 |
| | $ | — |
| | $ | 993 |
|
| Total realized / unrealized gains (losses) |
|
|
| |
|
|
| |
|
| | | | | | | |
|
|
| Included in net income | 3 |
|
| — |
| | (90 | ) | (a) | 3 |
| | (84 | ) | | — |
| | 3 |
| | — |
| | (81 | ) |
| Included in noncurrent payables to affiliates | 6 |
|
| — |
| | — |
| | — |
| | 6 |
| | — |
| | — |
| | (6 | ) | | — |
|
| Included in payable for Zion Station decommissioning | — |
|
| (8 | ) | | — |
| | — |
| | (8 | ) | | — |
| | | | — |
| | (8 | ) |
| Included in regulatory assets/liabilities | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| (b) | — |
| | 6 |
| | 8 |
|
| Change in collateral | — |
|
| — |
| | 20 |
| | — |
| | 20 |
| | — |
| | — |
| | — |
| | 20 |
|
| Purchases, sales, issuances and settlements |
|
|
| |
| |
| |
|
| | | | | | | |
|
|
| Purchases | 64 |
|
| 1 |
| | 178 |
| | 5 |
| | 248 |
| | — |
| | — |
| | — |
| | 248 |
|
| Sales | — |
|
| — |
| | (16 | ) |
| — |
| | (16 | ) | | — |
| | — |
| | — |
| | (16 | ) |
| Issuances | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
| Settlements | (102 | ) |
| — |
| | (8 | ) |
| — |
| | (110 | ) | | — |
| | — |
| | — |
| | (110 | ) |
| Transfers into Level 3 | — |
|
| — |
| | (6 | ) | (d) | — |
| | (6 | ) | | — |
| | — |
| | — |
| | (6 | ) |
| Transfers out of Level 3 | — |
|
| — |
| | (50 | ) | (d) | (11 | ) | | (61 | ) | | — |
| | — |
| | — |
| | (61 | ) |
| Other miscellaneous | $ | — |
| | $ | — |
| | $ | 31 |
| | $ | (2 | ) | | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 29 |
|
| Balance as of December 31, 2017 | $ | 648 |
|
| $ | 12 |
| | $ | 552 |
|
| $ | 37 |
|
| $ | 1,249 |
| | $ | (256 | ) | | $ | 22 |
| | $ | — |
| | $ | 1,015 |
|
| The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2017 | $ | 1 |
|
| $ | — |
| | $ | 254 |
|
| $ | 3 |
| | $ | 258 |
| | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 261 |
|
__________
| |
(a) | Includes a reduction for the reclassification of $265 million and $352 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2018 and 2017, respectively. |
| |
(b) | Includes $24 million of decreases in fair value and an increase for realized losses due to settlements of $17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2018. Includes $18 million of decreases in fair value and an increase for realized losses due to settlements of $20 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2017. |
| |
(c) | The amounts represented are life insurance contracts at Pepco. |
| |
(d) | Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts. |
| |
(e) | Includes $(19) million of fair value from contracts acquired as a result of the Everett Marine Terminal acquisition |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
The following tables present the income statement classificationrespectively. Exelon used an EROA of the total realized7.00% and unrealized gains (losses) included in income for Level 3 assets6.46% to estimate its 2021 pension and liabilities measuredOPEB costs, respectively.
Exelon’s pension and OPEB plan target asset allocations at fair value on a recurring basis during the years ended December 31, 20182020 and 2017:2019 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Asset Category | Pension Benefits | | OPEB | | Pension Benefits | | OPEB |
| Equity securities | 34 | % | | 45 | % | | 33 | % | | 46 | % |
| Fixed income securities | 43 | % | | 39 | % | | 44 | % | | 32 | % |
Alternative investments(a) | 23 | % | | 16 | % | | 23 | % | | 22 | % |
| Total | 100 | % | | 100 | % | | 100 | % | | 100 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | PHI | | Exelon |
| | Operating Revenues | | Purchased Power and Fuel | | Other, net | | Operating and
Maintenance | | Operating Revenues | | Purchased Power and Fuel | | Operating and
Maintenance | | Other, net |
| Total (losses) gains included in net income for the year ended December 31, 2018 | $ | (7 | ) | | $ | (93 | ) | | $ | 3 |
| | $ | 4 |
| | $ | (7 | ) | | $ | (93 | ) | | $ | 4 |
| | $ | 3 |
|
| Change in the unrealized gains relating to assets and liabilities held for the year ended December 31, 2018 | 144 |
| | 21 |
| | (2 | ) | | — |
| | 144 |
| | 21 |
| | — |
| | (2 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | PHI | | Exelon |
| | Operating Revenues | | Purchased Power and Fuel | | Other, net | | Operating and
Maintenance | | Operating Revenues | | Purchased Power and Fuel | | Operating and
Maintenance | | Other, net |
| Total gains (losses) included in net income for the year ended December 31, 2017 | $ | 28 |
| | $ | (126 | ) | | $ | 6 |
| | $ | 3 |
| | $ | 28 |
| | $ | (126 | ) | | $ | 3 |
| | $ | 6 |
|
| Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2017 | 290 |
| | (36 | ) | | 4 |
| | 3 |
| | 290 |
| | (36 | ) | | 3 |
| | 4 |
|
Valuation Techniques Used to Determine Fair Value
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.
Cash Equivalents (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE).The Registrants’ cash equivalents(a)Alternative investments include investments with original maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of theseprivate equity, hedge funds, are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.
NDT Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). The trust fund investments have been established to satisfy Generation’s and CENG's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in Equities and Fixed Income. Generation’s and CENG's NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.
With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds which are based on quoted prices in active markets are categorized in Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.
For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. With respect to individually held fixed income securities, the
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixed income securities, which are included in Corporate debt, are determined using a third-party valuation that contains significant unobservable inputs and are categorized in Level 3.
Equity and fixed income commingled funds and mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives such as holding short-term fixed income securities or tracking the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For commingled funds and mutual funds, which are not publicly quoted, the funds are valued using NAV as a practical expedient for fair value, which is primarily derived from the quoted prices in active markets on the underlying securities, and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.
Derivative instruments consisting primarily of futures and interest rate swaps to manage risk are recorded at fair value. Over the counter derivatives are valued daily based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over the counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.
Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models, and income models. Investments in loans are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Managed funds are valued using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.
Private equity and real estate, investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. The fair value of private equity and real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon’s understanding of the investment funds. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable.credit.
As of December 31, 2018, Generation has outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $127 million, $224 million, $326 million and $273 million, respectively. These commitments will be funded by Generation’s existing NDT funds.
Concentrations of Credit Risk. Generation Exelon evaluated its NDTpension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2018.2020. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2018,2020, there were no significant concentrations (generally defined(defined as greater than 10 percent)10% of plan assets) of risk in Generation's NDTExelon’s pension and OPEB plan assets.
See Note 15 — Asset Retirement Obligations for additional information on the NDT fund investments.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPLFair Value Measurements
The following tables present pension and ACE). The Rabbi trusts were established to holdOPEB plan assets related to deferred compensation plans existing for certain activemeasured and retired members of Exelon’s executive management and directors. The Rabbi trusts' assets are includedrecorded at fair value in investments in the Registrants’Exelon's Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities and life insurance policies. The mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3.
Mark-to-Market Derivatives (Exelon, Generation, ComEd, PHI and DPL).Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair valuehierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.
Exelon may utilize fixed-to-floating interest rate swaps as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 12 — Derivative Financial Instruments for additional information on mark-to-market derivatives.
Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.
The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a knownrecurring basis and certain stream of payments to be made over time and are categorized as Level 2their level within the fair value hierarchy.hierarchy at December 31, 2020 and 2019:
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| December 31, 2020 | | December 31, 2019 |
| Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Pension plan assets(a) | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | $ | 408 | | | $ | 121 | | | $ | 0 | | | $ | 0 | | | $ | 529 | | | $ | 258 | | | $ | 107 | | | $ | 0 | | | $ | 0 | | | $ | 365 | |
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Equities(b) | 4,255 | | | 0 | | | 2 | | | 2,552 | | | 6,809 | | | 3,616 | | | 1 | | | 5 | | | 2,589 | | | 6,211 | |
| Fixed income: | | | | | | | | | | | | | | | | | | | |
| U.S. Treasury and agencies | 1,137 | | | 367 | | | 0 | | | 0 | | | 1,504 | | | 1,294 | | | 280 | | | 0 | | | 0 | | | 1,574 | |
| State and municipal debt | 0 | | | 85 | | | 0 | | | 0 | | | 85 | | | 0 | | | 56 | | | 0 | | | 0 | | | 56 | |
Corporate debt(c) | 0 | | | 4,873 | | | 573 | | | 0 | | | 5,446 | | | 0 | | | 4,390 | | | 245 | | | 0 | | | 4,635 | |
Other(b) | 0 | | | 239 | | | 21 | | | 537 | | | 797 | | | 0 | | | 305 | | | 0 | | | 851 | | | 1,156 | |
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| Fixed income subtotal | 1,137 | | | 5,564 | | | 594 | | | 537 | | | 7,832 | | | 1,294 | | | 5,031 | | | 245 | | | 851 | | | 7,421 | |
| Private equity | 0 | | | 0 | | | 0 | | | 1,632 | | | 1,632 | | | 0 | | | 0 | | | 0 | | | 1,391 | | | 1,391 | |
| Hedge funds | 0 | | | 0 | | | 0 | | | 1,314 | | | 1,314 | | | 0 | | | 0 | | | 0 | | | 1,126 | | | 1,126 | |
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| Real estate | 0 | | | 0 | | | 0 | | | 1,080 | | | 1,080 | | | 0 | | | 0 | | | 0 | | | 1,030 | | | 1,030 | |
| Private credit | 0 | | | 0 | | | 234 | | | 1,046 | | | 1,280 | | | 0 | | | 0 | | | 237 | | | 929 | | | 1,166 | |
| Pension plan assets subtotal | 5,800 | | | 5,685 | | | 830 | | | 8,161 | | | 20,476 | | | 5,168 | | | 5,139 | | | 487 | | | 7,916 | | | 18,710 | |
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OPEB plan assets(a) | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 50 | | | 52 | | | 0 | | | 0 | | | 102 | | | 39 | | | 49 | | | 0 | | | 0 | | | 88 | |
| Equities | 618 | | | 2 | | | 0 | | | 569 | | | 1,189 | | | 473 | | | 5 | | | 0 | | | 719 | | | 1,197 | |
| Fixed income: | | | | | | | | | | | | | | | | | | | |
| U.S. Treasury and agencies | 16 | | | 66 | | | 0 | | | 0 | | | 82 | | | 17 | | | 64 | | | 0 | | | 0 | | | 81 | |
| State and municipal debt | 0 | | | 89 | | | 0 | | | 0 | | | 89 | | | 0 | | | 107 | | | 0 | | | 0 | | | 107 | |
Corporate debt(c) | 0 | | | 89 | | | 0 | | | 0 | | | 89 | | | 0 | | | 71 | | | 0 | | | 0 | | | 71 | |
| Other | 285 | | | 3 | | | 0 | | | 179 | | | 467 | | | 258 | | | 5 | | | 0 | | | 201 | | | 464 | |
| Fixed income subtotal | 301 | | | 247 | | | 0 | | | 179 | | | 727 | | | 275 | | | 247 | | | 0 | | | 201 | | | 723 | |
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| Hedge funds | 0 | | | 0 | | | 0 | | | 308 | | | 308 | | | 0 | | | 0 | | | 0 | | | 293 | | | 293 | |
| Real estate | 0 | | | 0 | | | 0 | | | 111 | | | 111 | | | 0 | | | 0 | | | 0 | | | 109 | | | 109 | |
| Private credit | 0 | | | 0 | | | 0 | | | 117 | | | 117 | | | 0 | | | 0 | | | 0 | | | 131 | | | 131 | |
| OPEB plan assets subtotal | 969 | | | 301 | | | 0 | | | 1,284 | | | 2,554 | | | 787 | | | 301 | | | 0 | | | 1,453 | | | 2,541 | |
Total pension and OPEB plan assets(d) | $ | 6,769 | | | $ | 5,986 | | | $ | 830 | | | $ | 9,445 | | | $ | 23,030 | | | $ | 5,955 | | | $ | 5,440 | | | $ | 487 | | | $ | 9,369 | | | $ | 21,251 | |
__________
(a)See Note 18—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.
(b)Includes derivative instruments of $2 million for the years ended December 31, 2020 and 2019, which have total notional amounts of $6,879 million and $6,668 million at December 31, 2020 and 2019, respectively. The notional principal
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Additional Information Regardingamounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.
(c)Includes investments in equities sold short held in investment vehicles primarily to hedge the equity option component of its convertible debt. Pension equities sold short totaled $(96) million and $(75) million as of December 31, 2020 and 2019, respectively. OPEB equities sold short totaled $(42) million and $(35) million as of December 31, 2020 and 2019, respectively.
(d)Excludes net liabilities of $132 million and $120 million at December 31, 2020 and 2019, respectively, which include certain derivative assets that have notional amounts of $239 million and $632 million at December 31, 2020 and 2019, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases and interest and dividends receivable.
The following table presents the reconciliation of Level 3 assets and liabilities for Exelon measured at fair value for pension and OPEB plans for the years ended December 31, 2020 and 2019:
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| | | | | | | Fixed Income | | Equities | | Private
Credit | | Total |
| Pension Assets | | | | | | | | | | | | | |
| Balance as of January 1, 2020 | | | | | | | $ | 245 | | | $ | 5 | | | $ | 237 | | | $ | 487 | |
| Actual return on plan assets: | | | | | | | | | | | | | |
Relating to assets still held at the
reporting date | | | | | | | 19 | | | (3) | | | 15 | | | 31 | |
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| Purchases, sales and settlements: | | | | | | | | | | | | | |
| Purchases | | | | | | | 34 | | | 0 | | | 24 | | | 58 | |
| | | | | | | | | | | | | |
Settlements(a) | | | | | | | (3) | | | 0 | | | (42) | | | (45) | |
Transfers into Level 3(b) | | | | | | | 299 | | | 0 | | | 0 | | | 299 | |
| Balance as of December 31, 2020 | | | | | | | $ | 594 | | | $ | 2 | | | $ | 234 | | | $ | 830 | |
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| | | | | | | Fixed Income | | Equities | | Private
Credit | | Total |
| Pension Assets | | | | | | | | | | | | | |
| Balance as of January 1, 2019 | | | | | | | $ | 216 | | | $ | 2 | | | $ | 268 | | | $ | 486 | |
| Actual return on plan assets: | | | | | | | | | | | | | |
Relating to assets still held at the reporting date | | | | | | | 28 | | | 3 | | | 28 | | | 59 | |
Relating to assets sold during the period | | | | | | | (7) | | | 0 | | | 0 | | | (7) | |
| Purchases, sales and settlements: | | | | | | | | | | | | | |
| Purchases | | | | | | | 26 | | | 0 | | | 41 | | | 67 | |
| Sales | | | | | | | (4) | | | 0 | | | 0 | | | (4) | |
Settlements(a) | | | | | | | (2) | | | 0 | | | (100) | | | (102) | |
| Transfers out of Level 3 | | | | | | | (12) | | | 0 | | | 0 | | | (12) | |
| Balance as of December 31, 2019 | | | | | | | $ | 245 | | | $ | 5 | | | $ | 237 | | | $ | 487 | |
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__________
(a)Represents cash settlements only.
(b)In 2020, a contract was terminated for a certain fixed income commingled fund resulting in the ownership of certain fixed income securities which led to a transfer into Level 3 from not subject to leveling of $299 million.
Valuation Techniques Used to Determine Fair Value Measurements (Exelon, Generation, ComEd, PHI, Pepco, DPL
The techniques used to fair value the pension and ACE)
OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real estate, and private credit investments are the same as the valuation techniques for these types of investments in NDTFs. See Cash Equivalents and NDT Fund Investments in Note 18 - Fair Value of Financial Assets and Pledged AssetsLiabilities for Zion StationDecommissioning (Exelonfurther information.
Pension and Generation).For middle market lendingOPEB assets also include investments in hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and certain corporate debt securities investments, theprovide additional diversification. The fair value is determined using a combinationof
Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Therefore, Generation has not disclosed such inputs.
Rabbi Trust Investments - Life insurance contracts (Exelon, PHI, Pepco, DPL and ACE). Forlife insurance policies categorized as Level 3, the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Therefore, Exelon has not disclosed such inputs.
Mark-to-Market Derivatives (Exelon, Generation and ComEd).For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements.
Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements.
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
hedge funds is determined using NAV or its equivalent as a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 powerpractical expedient, and gas delivery locations is approximately $3.18 and $0.64 for power and natural gas, respectively. Many of the commodity derivativestherefore, hedge funds are short term in nature and thus a majority ofnot classified within the fair value hierarchy. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may be based on observable inputs even thoughinclude a lock-up period or a gate.
Defined Contribution Savings Plan (All Registrants)
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the contract asIRC and allow employees to contribute a whole must be classified as Level 3.
On December 17, 2010, ComEd entered into several 20-year floatingportion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to fixed energy swap contracts with unaffiliated supplierscertain limits. The following table presents matching contributions to the savings plan for the procurement of long-term renewable energyyears ended December 31, 2020, 2019, and associated RECs. See Note 12 — Derivative Financial Instruments for additional information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.2018:
The following tables present the significant inputs to the forward curve used to value these positions: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2020 | $ | 158 | | | $ | 63 | | | $ | 36 | | | $ | 12 | | | $ | 13 | | | 14 | | | $ | 4 | | | $ | 3 | | | $ | 3 | |
| 2019 | 161 | | | 73 | | | 35 | | | 11 | | | 12 | | | 13 | | | 3 | | | 3 | | | 2 | |
| 2018 | 179 | | | 86 | | | 37 | | | 9 | | | 12 | | | 13 | | | 3 | | | 2 | | | 2 | |
|
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| Type of trade | | Fair Value at December 31, 2018 | | Valuation Technique | | Unobservable Input | | Range |
Mark-to-market derivatives—Economic hedges (Exelon and Generation)(a)(b) | | $ | 443 |
| | Discounted Cash Flow | | Forward power price | | $12 | - | $174 |
| | | | | | | Forward gas price | | $0.78 | - | $12.38 |
| | | | | Option Model | | Volatility percentage | | 10% | - | 277% |
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Mark-to-market derivatives—Proprietary trading (Exelon and Generation)(a)(b) | | $ | 56 |
| | Discounted Cash Flow | | Forward power price | | $14 | - | $174 |
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| Mark-to-market derivatives (Exelon and ComEd) | | $ | (249 | ) | | Discounted Cash Flow | | Forward heat rate(c) | | 10x | - | 11x |
| | | | | | | Marketability reserve | | 4% | - | 8% |
| | | | | | | Renewable factor | | 86% | - | 120% |
______
| |
(a) | The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. |
| |
(b) | The fair values do not include cash collateral posted on level three positions of $76 million as of December 31, 2018. |
| |
(c) | Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
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| Type of trade | | Fair Value at December 31, 2017 | | Valuation Technique | | Unobservable Input | | Range |
Mark-to-market derivatives—Economic hedges (Exelon and Generation)(a)(b) | | $ | 445 |
| | Discounted Cash Flow | | Forward power price | | $3 | - | $124 |
| | | | | | | Forward gas price | | $1.27 | - | $12.80 |
| | | | | Option Model | | Volatility percentage | | 11% | - | 139% |
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Mark-to-market derivatives— Proprietary trading (Exelon and Generation)(a)(b) | | $ | 26 |
| | Discounted Cash Flow | | Forward power price | | $14 | - | $94 |
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| Mark-to-market derivatives (Exelon and ComEd) | | $ | (256 | ) | | Discounted Cash Flow | | Forward heat rate(c) | | 9x | - | 10x |
| | | | | | | Marketability reserve | | 4% | - | 8% |
| | | | | | | Renewable factor | | 88% | - | 120% |
__________
| |
(a) | The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. |
| |
(b) | The fair values do not include cash collateral posted on level three positions $81 million as of December 31, 2017. |
| |
(c) | Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery. |
The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.
12.16. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange risk related to ongoing business operations.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings at Generation and are offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settles and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.
Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.
Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd are downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
Commodity Price Risk (All Registrants)
To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.
Derivative authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
economic hedges relatedGeneration. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to commoditiessell, Exelon and Generation are recorded at fair value through earnings for the consolidated company, referredexposed to as economic hedgesmarket fluctuations in the following tables. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portionprices of Generation’s overall energy marketing activities.
Fair value authoritative guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column. As of December 31, 2018, $2 million of cash collateral posted with external counterparties and an additional $12 million of cash collateral posted with ComEd, and as of December 31, 2017, $4 million of cash collateral held, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or had no positions to offset as of the balance sheet date. Excluded from the tables below are economic hedges that qualify for the NPNS scope exceptionelectricity, fossil fuels, and other non-derivative contracts that are accounted for under the accrual method of accounting.
ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e., to BB+ or Ba1).
Cash collateral held by PECO and BGE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
In the table below, DPL's economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a summary of the derivative fair value balances related to commodity contracts recorded by the Registrants as of December 31, 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | ComEd | | Exelon |
| Description | Economic Hedges | | Proprietary Trading | | Collateral and Netting(a)(d) | | Subtotal(b) | | Economic Hedges(c) | | Total Derivatives |
| Mark-to-market derivative assets (current assets) | $ | 3,505 |
| | $ | 105 |
| | $ | (2,809 | ) | | $ | 801 |
| | $ | — |
| | $ | 801 |
|
| Mark-to-market derivative assets (noncurrent assets) | 1,266 |
| | 41 |
| | (862 | ) | | 445 |
| | — |
| | 445 |
|
| Total mark-to-market derivative assets | 4,771 |
|
| 146 |
|
| (3,671 | ) | | 1,246 |
| | — |
|
| 1,246 |
|
| Mark-to-market derivative liabilities (current liabilities) | (3,429 | ) | | (74 | ) | | 3,056 |
| | (447 | ) | | (26 | ) | | (473 | ) |
| Mark-to-market derivative liabilities (noncurrent liabilities) | (1,203 | ) | | (20 | ) | | 972 |
| | (251 | ) | | (223 | ) | | (474 | ) |
| Total mark-to-market derivative liabilities | (4,632 | ) |
| (94 | ) |
| 4,028 |
| | (698 | ) | | (249 | ) |
| (947 | ) |
| Total mark-to-market derivative net assets (liabilities) | $ | 139 |
|
| $ | 52 |
|
| $ | 357 |
| | $ | 548 |
| | $ | (249 | ) |
| $ | 299 |
|
__________
| |
(a) | Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above. |
| |
(b) | Current and noncurrent assets are shown net of collateral of $121 million and $51 million, respectively, and current and noncurrent liabilities are shown net of collateral of $125 million and $60 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $357 million at December 31, 2018. |
| |
(c) | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
| |
(d) | Of the collateral posted/(received), $(94) million represents variation margin on the exchanges. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a summary of the derivative fair value balances related to commodity contracts recorded by the Registrants as of December 31, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | ComEd | | Exelon |
| Description | Economic Hedges | | Proprietary Trading | | Collateral and Netting(a)(d) | | Subtotal(b) | | Economic Hedges(c) | | Total Derivatives |
| Mark-to-market derivative assets (current assets) | $ | 3,061 |
| | $ | 56 |
| | $ | (2,144 | ) | | $ | 973 |
| | $ | — |
| | $ | 973 |
|
| Mark-to-market derivative assets (noncurrent assets) | 1,164 |
| | 12 |
| | (845 | ) | | 331 |
| | — |
| | 331 |
|
| Total mark-to-market derivative assets | 4,225 |
|
| 68 |
|
| (2,989 | ) | | 1,304 |
| | — |
|
| 1,304 |
|
| Mark-to-market derivative liabilities (current liabilities) | (2,646 | ) | | (43 | ) | | 2,480 |
| | (209 | ) | | (21 | ) | | (230 | ) |
| Mark-to-market derivative liabilities (noncurrent liabilities) | (1,137 | ) | | (10 | ) | | 975 |
| | (172 | ) | | (235 | ) | | (407 | ) |
| Total mark-to-market derivative liabilities | (3,783 | ) |
| (53 | ) |
| 3,455 |
| | (381 | ) | | (256 | ) |
| (637 | ) |
| Total mark-to-market derivative net assets (liabilities) | $ | 442 |
|
| $ | 15 |
|
| $ | 466 |
| | $ | 923 |
| | $ | (256 | ) |
| $ | 667 |
|
__________
| |
(a) | Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit and other forms of non-cash collateral. These are not reflected in the table above. |
| |
(b) | Current and noncurrent assets are shown net of collateral of $169 million and $53 million, respectively, and current and noncurrent liabilities are shown net of collateral of $167 million and $77 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $466 million at December 31, 2017. |
| |
(c) | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
| |
(d) | Of the collateral posted/(received), $(117) million represents variation margin on the exchanges. |
Economic Hedges (Commodity Price Risk)
commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.
Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.
Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.
| | | | | | | | | | | |
| Registrant | Commodity | Accounting Treatment | Hedging Instrument |
| ComEd | Electricity | NPNS | Fixed price contracts based on all requirements in the IPA procurement plans. |
| Electricity | Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a) | 20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year. |
PECO(b) | Gas | NPNS | Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales. |
| BGE | Electricity | NPNS | Fixed price contracts for all SOS requirements through full requirements contracts. |
| Gas | NPNS | Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. |
| Pepco | Electricity | NPNS | Fixed price contracts for all SOS requirements through full requirements contracts. |
| DPL | Electricity | NPNS | Fixed price contracts for all SOS requirements through full requirements contracts. |
| Gas | NPNS | Fixed and Index priced contracts through full requirements contracts. |
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(c) | Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections. |
| ACE | Electricity | NPNS | Fixed price contracts for all BGS requirements through full requirements contracts. |
_________
(a)See Note 3—Regulatory Matters for additional information.
(b)As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.
(c)The fair value of the DPL economic hedge is not material as of December 31, 2020 and 2019 and is not presented in the fair value tables below.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | | | | |
| December 31, 2020 | Total
Derivatives | | Economic
Hedges | | Proprietary
Trading | | Collateral (a)(b) | | Netting(a) | | Subtotal | | Economic
Hedges | | | | | | | | | |
| Mark-to-market derivative assets (current assets) | $ | 639 | | | $ | 2,757 | | | $ | 40 | | | $ | 103 | | | $ | (2,261) | | | $ | 639 | | | $ | 0 | | | | | | | | | | |
| Mark-to-market derivative assets (noncurrent assets) | 554 | | | 1,501 | | | 4 | | | 64 | | | (1,015) | | | 554 | | | 0 | | | | | | | | | | |
| Total mark-to-market derivative assets | 1,193 | | | 4,258 | | | 44 | | | 167 | | | (3,276) | | | 1,193 | | | 0 | | | | | | | | | | |
| Mark-to-market derivative liabilities (current liabilities) | (293) | | | (2,629) | | | (23) | | | 131 | | | 2,261 | | | (260) | | | (33) | | | | | | | | | | |
| Mark-to-market derivative liabilities (noncurrent liabilities) | (472) | | | (1,335) | | | (2) | | | 118 | | | 1,015 | | | (204) | | | (268) | | | | | | | | | | |
| Total mark-to-market derivative liabilities | (765) | | | (3,964) | | | (25) | | | 249 | | | 3,276 | | | (464) | | | (301) | | | | | | | | | | |
| Total mark-to-market derivative net assets (liabilities) | $ | 428 | | | $ | 294 | | | $ | 19 | | | $ | 416 | | | $ | 0 | | | $ | 729 | | | $ | (301) | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2019 | | | | | | | | | | | | | | | | | | | | | | |
| Mark-to-market derivative assets (current assets) | $ | 675 | | | $ | 3,506 | | | $ | 72 | | | $ | 287 | | | $ | (3,190) | | | $ | 675 | | | $ | 0 | | | | | | | | | | |
| Mark-to-market derivative assets (noncurrent assets) | 508 | | | 1,238 | | | 25 | | | 122 | | | (877) | | | 508 | | | 0 | | | | | | | | | | |
| Total mark-to-market derivative assets | 1,183 | | | 4,744 | | | 97 | | | 409 | | | (4,067) | | | 1,183 | | | 0 | | | | | | | | | | |
| Mark-to-market derivative liabilities (current liabilities) | (236) | | | (3,713) | | | (38) | | | 357 | | | 3,190 | | | (204) | | | (32) | | | | | | | | | | |
| Mark-to-market derivative liabilities (noncurrent liabilities) | (380) | | | (1,140) | | | (11) | | | 163 | | | 877 | | | (111) | | | (269) | | | | | | | | | | |
| Total mark-to-market derivative liabilities | (616) | | | (4,853) | | | (49) | | | 520 | | | 4,067 | | | (315) | | | (301) | | | | | | | | | | |
| Total mark-to-market derivative net assets (liabilities) | $ | 567 | | | $ | (109) | | | $ | 48 | | | $ | 929 | | | $ | 0 | | | $ | 868 | | | $ | (301) | | | | | | | | | | |
_________
(a)Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit, and other forms of non-cash collateral. These amounts are not material and not reflected in the table above.
(b)Of the collateral posted, $209 million and $511 million represents variation margin on the exchanges at December 31, 2020 and 2019, respectively.
Economic Hedges (Commodity Price Risk)
Generation. For the years ended December 31, 2018, 20172020, 2019, and 2016,2018, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the "NetNet fair value changes related to derivatives"derivatives line in the Consolidated Statements of Cash Flows.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
| | | | | For the Years Ended December 31, | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 | | Gain (Loss) |
| Income Statement Location | | Gain (Loss) | Income Statement Location | | 2020 | | 2019 | | 2018 |
| | Operating revenues | | $ | (270 | ) | | $ | (126 | ) | | $ | (490 | ) | Operating revenues | | $ | 112 | | | $ | 0 | | | $ | (270) | |
| Purchased power and fuel | | (47 | ) | | (43 | ) | | 459 |
| Purchased power and fuel | | 168 | | | (204) | | | (47) | |
| Total Exelon and Generation | | $ | (317 | ) | | $ | (169 | ) | | $ | (31 | ) | Total Exelon and Generation | | $ | 280 | | | $ | (204) | | | $ | (317) | |
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
price risk on a ratable basis over three-year periods. As of December 31, 2018,2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 89%-92%, 56%-59% and 32%-35%94%-97% for 2019, 2020 and 2021, respectively.
On December 17, 2010, ComEd executed several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 4 — Regulatory Matters for additional information.
PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2018 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2018 and previous PGC settlements, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 20% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s results of operations and financial position as natural gas costs are fully recovered from customers under the PGC.
BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE’s wholesale power supply costs and include an administrative fee. BGE’s commodity price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives.
BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. BGE’s natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery.
Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco's wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s commodity price risk related to electric supply procurement is limited. Pepco locks in fixed prices for its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.
DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and the DPSC. The SOS rates charged recover DPL's wholesale power supply costs. In Delaware, DPL is also entitled to recover a Reasonable Allowance for Retail Margin (RARM). The RARM includes a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. In Maryland, DPL charges an administrative fee intended to allow it to recover its administrative
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
costs. DPL locks in fixed prices for its SOS requirements through full requirements contracts. DPL’s commodity price risk related to electric supply procurement is limited. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.
DPL provides natural gas to its customers under an Annual GCR mechanism approved by the DPSC. Under this mechanism, DPL’s Annual GCR Filing establishes a future GCR for firm bundled sales customers by using a forecast of demand and commodity costs. The actual costs are trued up against forecast on a monthly basis and any shortfall or excess is carried forward as a recovery balance in the next GCR filing. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas. The hedge program requires that DPL hedge, on a non-discretionary basis, an amount equal to 50% of estimated purchase requirements for each month, including estimated monthly purchases for storage injections. The 50% hedge monthly target is achieved by hedging 1/12th of the 50% target each month beginning 12-months prior to the month in which the physical gas is to be purchased. Currently, DPL uses only exchange traded futures for its gas hedging program, which are considered derivatives, however, it retains the capability to employ other physical and financial hedges if needed. DPL has not elected hedge accounting for these derivative financial instruments. Because of the DPSC-approved fuel adjustment clause for DPL's derivatives, the change in fair value of the derivatives each period, in addition to all premiums paid and other transaction costs incurred as part of the Gas Hedging Program, are fully recoverable and are recorded by DPL as regulatory assets or liabilities. DPL’s physical gas purchases are currently all daily, monthly or intra-month transactions. From time to time, DPL will enter into seasonal purchase or sale arrangements, however, there are none currently in the portfolio. Certain of DPL's full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.
ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE's wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s commodity price risk related to electric supply procurement is limited. ACE locks in fixed prices for its BGS requirements through full requirements contracts. Certain of ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.2021.
Proprietary Trading (Commodity Price Risk)
Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon's RMC monitor the financial risks of the proprietary trading activities. The proprietary trading activities are a complement to Generation's energy marketing portfolio but represent a small portion of Generation's overall revenue from energy marketing activities. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the years ended December 31, 2018, 20172020, 2019, and 2016, Exelon and Generation recognized the following2018, net pre-tax commodity mark-to-market gains (losses) which are also included in the "Net fair value changes related to derivatives" in the Consolidated Statements of Cash Flows.and losses for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.
|
| | | | | | | | | | | | |
| | | For the Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| Income Statement Location | | Gain |
| Operating revenues | | $ | 17 |
| | $ | 6 |
| | $ | 2 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Interest Rate and Foreign Exchange Risk (All Registrants)(Exelon and Generation)
The Registrants use a combination of fixed-rateExelon and variable-rate debt to manage interest rate exposure. The Registrants alsoGeneration utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. To manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are treated as economic hedges. Below is a summary of the interest rate and foreign exchange hedge balances as of December 31, 2018:
|
| | | | | | | | | | | | | | | | | | | | |
| | Generation | | Exelon Corporate | | Exelon |
| Description | | Economic Hedges | | Collateral and Netting(a) | | Subtotal | | Economic
Hedges | | Total |
| Mark-to-market derivative assets (current assets) |
| $ | 5 |
|
| $ | (2 | ) | | $ | 3 |
| | $ | — |
| | $ | 3 |
|
| Mark-to-market derivative assets (noncurrent assets) |
| 8 |
|
| (1 | ) | | 7 |
| | — |
| | 7 |
|
| Total mark-to-market derivative assets |
| 13 |
|
| (3 | ) | | 10 |
| | — |
| | 10 |
|
| Mark-to-market derivative liabilities (current liabilities) |
| (4 | ) |
| 2 |
| | (2 | ) | | — |
| | (2 | ) |
| Mark-to-market derivative liabilities (noncurrent liabilities) |
| (2 | ) |
| 1 |
| | (1 | ) | | (4 | ) | | (5 | ) |
| Total mark-to-market derivative liabilities |
| (6 | ) |
| 3 |
| | (3 | ) | | (4 | ) | | (7 | ) |
| Total mark-to-market derivative net assets (liabilities) |
| $ | 7 |
|
| $ | — |
| | $ | 7 |
| | $ | (4 | ) | | $ | 3 |
|
__________
| |
(a) | Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral, which are not reflected in the table above. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | Exelon Corporate | | Exelon |
| Description | Derivatives Designated as Hedging Instruments | | Economic Hedges | | Collateral and Netting(a) | | Subtotal | | Derivatives
Designated
as Hedging
Instruments | | Total |
| Mark-to-market derivative assets (current assets) | $ | — |
| | $ | 10 |
| | $ | (7 | ) | | $ | 3 |
| | $ | — |
| | $ | 3 |
|
| Mark-to-market derivative assets (noncurrent assets) | 3 |
| | — |
| | — |
| | 3 |
| | 3 |
| | 6 |
|
| Total mark-to-market derivative assets | 3 |
|
| 10 |
|
| (7 | ) | | 6 |
| | 3 |
| | 9 |
|
| Mark-to-market derivative liabilities (current liabilities) | (2 | ) | | (7 | ) | | 7 |
| | (2 | ) | | — |
| | (2 | ) |
| Mark-to-market derivative liabilities (noncurrent liabilities) | — |
| | (2 | ) | | — |
| | (2 | ) | | — |
| | (2 | ) |
| Total mark-to-market derivative liabilities | (2 | ) |
| (9 | ) |
| 7 |
| | (4 | ) | | — |
| | (4 | ) |
| Total mark-to-market derivative net assets (liabilities) | $ | 1 |
|
| $ | 1 |
|
| $ | — |
| | $ | 2 |
| | $ | 3 |
| | $ | 5 |
|
__________
| |
(a) | Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral, which are not reflected in the table above. |
Economic Hedges (Interest Rate and Foreign Exchange Risk)
Exelon and Generation execute these instruments to mitigate exposure to fluctuations in interest rates or foreign exchange but for which the fair value or cash flow hedge elections were not made. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The amount deferred in AOCI associated with the previously designated cash flow hedges will be reclassified into earnings as the underlying forecasted transaction occurs. The result of this de-designation is that all economic hedges for interest rate swaps will be recorded at fair value through earnings going forward, referred to as economic hedges in the following tables.
The following table provides notional amounts outstanding held by Exelonwere $516 million and Generation$1,269 million at December 31, 2018 related to interest rate swaps2020 and foreign currency exchange rate swaps.
|
| | | | | | | | | | | | |
| | | Generation | | Exelon Corporate | | Exelon |
| Foreign currency exchange rate swaps | | $ | 268 |
| | $ | — |
| | $ | 268 |
|
| Interest rate swaps | | 620 |
| | 800 |
| | 1,420 |
|
| Total | | $ | 888 |
| | $ | 800 |
| | $ | 1,688 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides notional amounts outstanding held by2019, respectively, for Exelon and Generation$516 million and $569 million at December 31, 2017 related to interest rate swaps2020 and 2019, respectively, for Generation.
Generation utilizes foreign currency derivatives to manage foreign exchange rate swaps.
|
| | | | | | | | | | | | |
| | | Generation | | Exelon Corporate | | Exelon |
| Foreign currency exchange rate swaps | | $ | 94 |
| | $ | — |
| | $ | 94 |
|
Interest rate swaps(a) | | 1 |
| | — |
| | 1 |
|
| Total | | $ | 95 |
| | $ | — |
| | $ | 95 |
|
__________
| |
(a) | On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. The table excludes amounts of $800 million of fixed-to-floating hedges that were previously designated as fair value hedges by Exelon and $636 million of floating-to-fixed hedges that were previously designated as cash flow hedges by Exelon and Generation as of December 31, 2017. |
For the years endedexposure associated with international commodity purchases in currencies other than U.S. dollars, which are treated as economic hedges. The notional amounts were $149 million and $231 million at December 31, 2018, 20172020 and 2016, Exelon2019, respectively.
The mark-to-market derivative assets and Generation recognized the following net pre-tax mark-to-market gains (losses) in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows.
|
| | | | | | | | | | | | | | |
| | | | | For the Years Ended December 31, |
| | | | | 2018 | | 2017 | | 2016 |
| | | Income Statement Location | | Gain (Loss) |
| Generation | | Operating Revenues | | $ | 7 |
| | $ | (6 | ) | | $ | (10 | ) |
| Generation | | Purchased Power and Fuel | | (9 | ) | | — |
| | — |
|
| Generation | | Interest Expense | | (7 | ) | | (3 | ) | | — |
|
| Total Generation | | | | $ | (9 | ) | | $ | (9 | ) | | $ | (10 | ) |
|
| | | | | | | | | | | | | | |
| | | | | For the Years Ended December 31, |
| | | | | 2018 | | 2017 | | 2016 |
| | | Income Statement Location | | Gain (Loss) |
| Exelon | | Operating Revenues | | $ | 7 |
| | $ | (6 | ) | | $ | (10 | ) |
| Exelon | | Purchased Power and Fuel | | (9 | ) | | — |
| | — |
|
| Exelon | | Interest Expense | | (4 | ) | | (3 | ) | | — |
|
| Total Exelon | | | | $ | (6 | ) | | $ | (9 | ) | | $ | (10 | ) |
Fair Value Hedges (Interest Rate Risk)
For derivative instruments that qualify and are designated as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in earnings immediately. Exelon had no fixed-to-floating swaps designated as fair value hedgesliabilities as of December 31, 20182020 and had $800 million notional amounts designated as fair value hedges as of December 31, 2017. Exelon and Generation include the gain or loss on the hedged items2019 and the offsetting loss or gain on the related interest rate swaps as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Year Ended December 31, |
| | Income Statement Location | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| | Loss on Swaps | | Gain on Borrowings |
| Exelon | Interest expense | | $ | (11 | ) | | $ | (13 | ) | | $ | (9 | ) | | $ | 20 |
| | $ | 28 |
| | $ | 23 |
|
During the years ended December 31, 2018, 2017mark-to-market gains and 2016, the impact on the results of operations due to ineffectiveness from fair value hedges were gains of $9 million, $15 million and $14 million, respectively.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Cash Flow Hedges (Interest Rate Risk)
For derivative instruments that qualify and are designated as cash flow hedges, the gain or loss on the effective portion of the derivative will be deferred in AOCI and reclassified into earnings when the underlying transaction occurs. Exelon and Generation have no floating-to-fixed swaps designated as cash flow hedges as of December 31, 2018, and had $636 million notional amounts designated as cash flow hedges as of December 31, 2017.
The tables below provide the activity of OCI related to cash flow hedgeslosses for the years ended December 31, 2020, 2019, and 2018 and 2017, containing information about the changes in the fair value of cash flow hedges and the reclassification from AOCI into results of operations. The amounts reclassified from AOCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.
|
| | | | | | | | | | | |
| | | | | Total Cash Flow Hedge AOCI Activity, Net of Income Tax | |
| | | | | Generation | | Exelon | |
| For the Year Ended December 31, 2018 | | Income Statement Location | | Total Cash
Flow Hedges | | Total Cash Flow Hedges | |
| AOCI derivative loss at December 31, 2017 | | | | $ | (16 | ) | | $ | (14 | ) | |
| Effective portion of changes in fair value | | | | 11 |
| | 11 |
| |
| Reclassifications from AOCI to net income | | Interest expense | | 1 |
| | 1 |
| |
| AOCI derivative loss at December 31, 2018 | | | | $ | (4 | ) | | $ | (2 | ) | |
|
| | | | | | | | | | | |
| | | | | Total Cash Flow Hedge AOCI Activity, Net of Income Tax | |
| | | | | Generation | | Exelon | |
| For the Year Ended December 31, 2017 | | Income Statement Location | | Total Cash
Flow Hedges | | Total Cash Flow Hedges | |
| AOCI derivative loss at December 31, 2016 | | | | $ | (19 | ) | | $ | (17 | ) | |
| Effective portion of changes in fair value | | | | (1 | ) | | (1 | ) | |
| Reclassifications from AOCI to net income | | Interest expense | | 4 |
| (a) | 4 |
| (a) |
| AOCI derivative loss at December 31, 2017 | | | | $ | (16 | ) | | $ | (14 | ) | |
__________
| |
(a) | Amount is net of related income tax expense of $1 millionwere not material for the year ended December 31, 2017. |
During the years ended December 31, 2018, 2017 and 2016, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial. The estimated amount of existing gains and losses that are reported in AOCI at the reporting date that are expected to be reclassified into earnings within the next twelve months is immaterial.
Proprietary Trading (Interest Rate and Foreign Exchange Risk)
Generation also executes derivative contracts for proprietary trading purposes to hedge risk associated with the interest rate and foreign exchange components of underlying commodity positions. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. For the years ended December 31, 2018, 2017 and 2016, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses).
|
| | | | | | | | | | | | |
| | | For the Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| Income Statement Location | | Loss |
| Operating revenues | | $ | — |
| | $ | (1 | ) | | $ | (1 | ) |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation.
Credit Risk Collateral and Contingent-Related Features (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date.
Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2018.2020. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $43 million, $30 million, $24 million, $28 million, $7 million and $5 million as of December 31, 2018, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Rating as of December 31, 2020 | Total
Exposure
Before Credit
Collateral | | Credit Collateral(a) | | Net
Exposure | | Number of
Counterparties
Greater than 10%
of Net Exposure | | Net Exposure of
Counterparties
Greater than 10%
of Net Exposure |
| Investment grade | $ | 577 | | | $ | 27 | | | $ | 550 | | | 0 | | | $ | 0 | |
| Non-investment grade | 32 | | | 0 | | | 32 | | | | | |
| No external ratings | | | | | | | | | |
| Internally rated — investment grade | 165 | | | 1 | | | 164 | | | | | |
| Internally rated — non-investment grade | 80 | | | 28 | | | 52 | | | | | |
| Total | $ | 854 | | | $ | 56 | | | $ | 798 | | | 0 | | | $ | 0 | |
|
| | | | | | | | | | | | | | | | | | |
| Rating as of December 31, 2018 | Total Exposure Before Credit Collateral | | Credit Collateral (a) | | Net Exposure | | Number of Counterparties Greater than 10% of Net Exposure | | Net Exposure of Counterparties Greater than 10% of Net Exposure |
| Investment grade | $ | 795 |
|
| $ | — |
| | $ | 795 |
| | 1 |
| | $ | 153 |
|
| Non-investment grade | 133 |
|
| 45 |
| | 88 |
| | — |
| | — |
|
| No external ratings |
|
|
| |
| | | | |
| Internally rated — investment grade | 181 |
|
| 1 |
| | 180 |
| | — |
| | — |
|
| Internally rated — non-investment grade | 92 |
|
| 6 |
| | 86 |
| | — |
| | — |
|
| Total | $ | 1,201 |
|
| $ | 52 |
| | $ | 1,149 |
| | 1 |
| | $ | 153 |
|
|
| | | |
| Net Credit Exposure by Type of Counterparty | December 31, 2018 |
| Financial institutions | $ | 12 |
|
| Investor-owned utilities, marketers, power producers | 737 |
|
| Energy cooperatives and municipalities | 324 |
|
| Other | 76 |
|
| Total | $ | 1,149 |
|
__________
| | | | | |
(a)Net Credit Exposure by Type of Counterparty | As of December 31, 2018, credit collateral held from counterparties where Generation had credit exposure included $17 million of cash2020 |
| Financial institutions | $ | 15 | |
| Investor-owned utilities, marketers, power producers | 607 | |
Energy cooperatives and $35 million of letters of credit. The credit collateral does not include non-liquid collateral.municipalities | 138 | |
| Other | 38 | |
| Total | $ | 798 | |
ComEd’s power procurement__________
(a)As of December 31, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $25 million of letters of credit. The credit collateral does not include non-liquid collateral.
Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. The credit position is based on daily, updated forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energyexposure on the supply contract exceeds the benchmark price on a given day,amount of unsecured credit, the suppliers aremay be required to
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
post collateral for the securedcollateral. The net credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit usedexposure is mitigated primarily by the suppliers represents ComEd’s net credit exposure. The unsecured credit used by the suppliers represents ComEd’s net credit exposure.ability to recover procurement costs through customer rates. As of December 31, 2018, ComEd’s net credit exposure to suppliers was immaterial.
ComEd is permitted to recover its costs of procuring energy through2020, the Illinois Settlement Legislation. ComEd’sUtility Registrants’ counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 4 — Regulatory Matters for additional information.with suppliers was not material.
PECO’s unsecured credit used by electric suppliers represents PECO’s net credit exposure. As of December 31, 2018, PECO had no material net credit exposure to electric suppliers.
PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. As of December 31, 2018, PECO had no material credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.
BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 4 — Regulatory Matters for additional information.
BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. As of December 31, 2018, BGE had no material net credit exposure to suppliers.
BGE’s regulated gas business is exposed to market-price risk. At December 31, 2018, BGE had credit exposure of $3 million related to off-system sales which is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with those third-party suppliers.
Pepco’s, DPL's and ACE's power procurement contracts provide suppliers with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents Pepco’s, DPL's and ACE's net credit exposure. As of December 31, 2018, Pepco’s, DPL's and ACE's net credit exposures to suppliers were immaterial.
Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy through the NJBPU-approved procurement tariffs. Pepco’s, DPL's and ACE's counterparty credit risks are mitigated by their ability to recover realized energy costs through customer rates. See Note 4 — Regulatory Matters for additional information.
DPL’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the DPSC. DPL’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the GCR, which allows DPL to adjust rates annually to reflect realized natural gas prices. To the extent that the fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder. As of December 31, 2018, DPL's credit exposure under its natural gas supply and asset management agreements was immaterial.
CollateralCredit-Risk-Related Contingent Features (All Registrants)
Generation. As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
The aggregate fair value of all derivative instruments with credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:
| | | | | | | | As of December 31, |
| | For the Years Ended December 31, | |
| Credit-Risk Related Contingent Feature | 2018 | | 2017 | |
| Credit-Risk Related Contingent Features | | Credit-Risk Related Contingent Features | | 2020 | | 2019 |
Gross fair value of derivative contracts containing this feature(a) | $ | (1,723 | ) | | $ | (926 | ) | Gross fair value of derivative contracts containing this feature(a) | | $ | (834) | | | $ | (956) | |
Offsetting fair value of in-the-money contracts under master netting arrangements(b) | 1,105 |
| | 577 |
| Offsetting fair value of in-the-money contracts under master netting arrangements(b) | | 537 | | | 649 | |
Net fair value of derivative contracts containing this feature(c) | $ | (618 | ) | | $ | (349 | ) | Net fair value of derivative contracts containing this feature(c) | | $ | (297) | | | $ | (307) | |
__________
| |
(a) | (a)Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements. (b)Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which Generation could potentially be required to post collateral. (c)Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based. As of December 31, 2020 and 2019, Exelon and Generation posted or held the following amounts of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements. |
| |
(b) | Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral. |
| |
(c) | Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based. |
Generation had cash collateral posted of $418 million and letters of credit posted of $367 million, and cash collateral held of $47 million and letters of credit held of $44 million as of December 31, 2018 foron derivative contracts with external counterparties, with derivative positions. Generation had cash collateral posted of $497 million and letters of credit posted of $293 million and cash collateral held of $35 million and letters of credit held of $33 million at December 31, 2017 for external counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e., to BB+ by S&P or Ba1 by Moody's), Generation would have been required to post additional collateral of $2.1 billion and $1.8 billion as of December 31, 2018 and 2017, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Generation’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of December 31, 2018, Generation’s and Exelon's swaps were in an asset position with a fair value of $7 million and $3 million, respectively.
See Note 24 — Segment Information for additional information regarding the letters of credit supporting the cash collateral. | | | | | | | | | | | | | | |
| | As of December 31, |
| | 2020 | | 2019 |
| Cash collateral posted | | $ | 511 | | | $ | 982 | |
| Letters of credit posted | | 226 | | | 264 | |
| Cash collateral held | | 110 | | | 103 | |
| Letters of credit held | | 40 | | | 112 | |
| Additional collateral required in the event of a credit downgrade below investment grade | | 1,432 | | | 1,509 | |
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels,
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd’s standard block energy
Utility Registrants
The Utility Registrants’ electric supply procurement contracts collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of December 31, 2018, ComEd held approximately $38 million in collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's ZEC contracts, collateral postings are required to cover a percentage of the ZEC contract value. ComEd’s REC contractsdo not contain provisions that would require collateral postings that are either a fixed price per REC or a percentage of the REC contract value. As of December 31, 2018, ComEd held approximately $31 million in collateral from suppliers for REC and ZEC contract obligations. Under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of December 31, 2018, ComEd held approximately $19 million in collateral from suppliers for the long-term renewable energy contracts. If ComEd lost its investment grade credit rating as of December 31, 2018, it would have been requiredthem to post approximately $7 million of collateral to its counterparties. See Note 4 — Regulatory Matters for additional information.collateral.
PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral. This collateral may be posted in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.rating. As of December 31, 2018,2020, PECO, wasBGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost itstheir investment grade credit rating as of December 31, 2018, PECO2020, they could have been required to post approximately $39 million ofincremental collateral to its counterparties.their counterparties of $34 million, $54 million, and $9 million, respectively.
PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.
BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2018, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of December 31, 2018, BGE could have been required to post approximately $69 million of collateral to its counterparties.
DPL's natural gas procurement contracts contain provisions that could require DPL to post collateral. To the extent that the fair value of the natural gas derivative transaction in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The DPL obligations are standalone, without the guaranty of PHI. If DPL lost its investment grade credit rating as of December 31, 2018, DPL could have been required to post an additional amount of approximately $11 million of collateral to its natural gas counterparties.
BGE's, Pepco's, DPL's and ACE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE, Pepco, DPL or ACE to post collateral.
13.17. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, BGE, Pepco, DPL and ACEBGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and borrowings from the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Commercial Paper
The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at December 31, 20182020 and 2017:2019:
| | | | Maximum Program Size at December 31, | | Outstanding Commercial Paper at December 31, | | Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31, | | Maximum
Program Size at
December 31, | | Outstanding
Commercial
Paper at
December 31, | | Average Interest Rate on
Commercial Paper Borrowings at December 31, |
| Commercial Paper Issuer | 2018(a)(b)(c) | | 2017(a)(b)(c) | | 2018 | | 2017 | | 2018 | | 2017 | Commercial Paper Issuer | 2020(a)(b)(c) | | 2019(a)(b)(c) | | 2020 | | 2019 | | 2020 | | 2019 |
| Exelon Corporate | $ | 600 |
| | $ | 600 |
| | $ | — |
| | $ | — |
| | 1.93 | % | | 1.16 | % | |
Exelon(d) | | Exelon(d) | $ | 9,000 | | | $ | 9,000 | | | $ | 1,031 | | | $ | 870 | | | 0.25 | % | | 2.25 | % |
| Generation | 5,300 |
| | 5,300 |
| | — |
| | — |
| | 1.96 | % | | 1.23 | % | Generation | 5,300 | | | 5,300 | | | 340 | | | 320 | | | 0.27 | % | | 1.84 | % |
| ComEd | 1,000 |
| | 1,000 |
| | — |
| | — |
| | 2.14 | % | | 1.24 | % | ComEd | 1,000 | | | 1,000 | | | 323 | | | 130 | | | 0.23 | % | | 2.38 | % |
| PECO | 600 |
| | 600 |
| | — |
| | — |
| | 2.24 | % | | 1.13 | % | PECO | 600 | | | 600 | | | 0 | | | 0 | | | 0 | % | | 2.39 | % |
| BGE | 600 |
| | 600 |
| | 35 |
| | 77 |
| | 2.18 | % | | 1.28 | % | BGE | 600 | | | 600 | | | 0 | | | 76 | | | 0 | % | | 2.46 | % |
PHI(e) | | PHI(e) | 900 | | | 900 | | | 368 | | | 208 | | | 0.24 | % | | N/A |
| Pepco | 300 |
| | 500 |
| | 40 |
| | 26 |
| | 2.24 | % | | 1.06 | % | Pepco | 300 | | | 300 | | | 35 | | | 82 | | | 0.22 | % | | 2.56 | % |
| DPL | 300 |
| | 500 |
| | — |
| | 216 |
| | 2.07 | % | | 1.48 | % | DPL | 300 | | | 300 | | | 146 | | | 56 | | | 0.24 | % | | 2.02 | % |
| ACE | 300 |
| | 350 |
| | 14 |
| | 108 |
| | 2.21 | % | | 1.43 | % | ACE | 300 | | | 300 | | | 187 | | | 70 | | | 0.25 | % | | 2.43 | % |
| Total | $ | 9,000 |
|
| $ | 9,450 |
|
| $ | 89 |
|
| $ | 427 |
| | | | | |
__________
| |
(a) | Excludes $545 million and $480 million in bilateral credit facilities at December 31, 2018 and 2017, respectively, and $159 million and $179 million in credit facilities for project finance at December 31, 2018 and 2017, respectively. These credit facilities do not back Generation's commercial paper program. |
| |
(b) | At December 31, 2018, excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, $5 million and $5 million, respectively. These facilities expire on October 11, 2019. These facilities are solely utilized to issue letters of credit. At December 31, 2017, excludes $128 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $34 million, $34 million, $5 million, $2 million, $2 million, and $2 million, respectively. |
| |
(c) | Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility. |
(a)Excludes $1,500 million and $1,400 million in bilateral credit facilities at December 31, 2020 and 2019, respectively, and $144 million and $159 million in credit facilities for project finance at December 31, 2020 and 2019, respectively. These credit facilities do not back Generation's commercial paper program.
(b)At December 31, 2020, excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $38 million, $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. These facilities expire on October 8, 2021. These facilities are solely utilized to issue letters of credit. At December 31, 2019, excludes $142 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $44 million, $33 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively.
(c)Pepco, DPL, and ACE's revolving credit facility has the ability to flex to $500 million, $500 million, and $350 million, respectively. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL, or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.
(d)Includes revolving credit agreement at Exelon Corporate with a maximum program size of $600 million at both December 31, 2020 and 2019, respectively. Exelon Corporate had 0 outstanding commercial paper as of December 31, 2020 and $136 million at 2019 with an average interest rate on commercial paper borrowings of 1.92%.
(e)Represents the consolidated amounts of Pepco, DPL, and ACE.
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of outstanding commercial paper does not reduce available capacity under a Registrant’s credit facility, a RegistrantA registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
At December 31, 2018,2020, the Registrants had the following aggregate bank commitments, credit facility borrowings, and available capacity under their respective credit facilities:
| | | | | | | | | | | | | | | Available Capacity at December 31, 2020 |
| | | | | | | | | Available Capacity at December 31, 2018 | |
| Borrower | Facility Type | | Aggregate Bank
Commitment(a) | | Facility Draws | | Outstanding Letters of Credit | | Actual | | To Support Additional Commercial
Paper(b) | |
| Exelon Corporate | Syndicated Revolver | | $ | 600 |
| | $ | — |
| | $ | 9 |
| | $ | 591 |
| | $ | 591 |
| |
Borrower(a) | | Borrower(a) | Facility Type | | Aggregate Bank
Commitment(b) | | Facility Draws | | Outstanding
Letters of Credit | | Actual | | To Support Additional Commercial
Paper(c) |
Exelon(c) | | Exelon(c) | Syndicated Revolver / Bilaterals / Project Finance | | $ | 10,644 | | | $ | 0 | | | $ | 1,230 | | | $ | 9,414 | | | $ | 7,698 | |
| Generation | Syndicated Revolver | | 5,300 |
| | — |
| | 1,203 |
| | 4,097 |
| | 4,097 |
| Generation | Syndicated Revolver | | 5,300 | | | 0 | | | 262 | | | 5,038 | | | 4,698 | |
| Generation | Bilaterals | | 545 |
| | — |
| | 353 |
| | 192 |
| | — |
| Generation | Bilaterals | | 1,500 | | | 0 | | | 840 | | | 660 | | | 0 | |
| Generation | Project Finance | | 159 |
| | — |
| | 119 |
| | 40 |
| | — |
| Generation | Project Finance | | 144 | | | 0 | | | 119 | | | 25 | | | 0 | |
| ComEd | Syndicated Revolver | | 1,000 |
| | — |
| | 2 |
| | 998 |
| | 998 |
| ComEd | Syndicated Revolver | | 1,000 | | | 0 | | | 2 | | | 998 | | | 675 | |
| PECO | Syndicated Revolver | | 600 |
| | — |
| | — |
| | 600 |
| | 600 |
| PECO | Syndicated Revolver | | 600 | | | 0 | | | 0 | | | 600 | | | 600 | |
| BGE | Syndicated Revolver | | 600 |
| | — |
| | 1 |
| | 599 |
| | 564 |
| BGE | Syndicated Revolver | | 600 | | | 0 | | | 0 | | | 600 | | | 600 | |
| PHI | | PHI | Syndicated Revolver | | 900 | | | 0 | | | 1 | | | 899 | | | 531 | |
| Pepco | Syndicated Revolver | | 300 |
| | — |
| | 8 |
| | 292 |
| | 252 |
| Pepco | Syndicated Revolver | | 300 | | | 0 | | | 1 | | | 299 | | | 264 | |
| DPL | Syndicated Revolver | | 300 |
| | — |
| | 1 |
| | 299 |
| | 299 |
| DPL | Syndicated Revolver | | 300 | | | 0 | | | 0 | | | 300 | | | 154 | |
| ACE | Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 286 |
| ACE | Syndicated Revolver | | 300 | | | 0 | | | 0 | | | 300 | | | 113 | |
| Total | | $ | 9,704 |
| | $ | — |
| | $ | 1,696 |
| | $ | 8,008 |
| | $ | 7,687 |
| |
__________
| |
(a) | Excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, $5 million and $5 million, respectively. These facilities expire on October 11, 2019. These facilities are solely utilized to issue letters of credit. As of December 31, 2018, letters of credit issued under these facilities totaled $5 million and $2 million for Generation and BGE, respectively. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE during 2018, 2017 and 2016.
|
| | | | | | | | | | | | |
| Exelon | | | | | | |
| | 2018 | | 2017 | | | 2016 |
| Average borrowings | $ | 531 |
| | $ | 823 |
| | | $ | 1,125 |
|
| Maximum borrowings outstanding | 1,237 |
| | 2,147 |
| | | 3,076 |
|
| Average interest rates, computed on a daily basis | 2.21 | % | | 1.32 | % | | | 0.88 | % |
| Average interest rates, at December 31 | 2.15 | % | | 1.24 | % | | | 1.12 | % |
| | | | | | | |
| Generation | | | | | | |
| | 2018 | | 2017 | | | 2016 |
| Average borrowings | $ | 37 |
| | $ | 405 |
| | | $ | 536 |
|
| Maximum borrowings outstanding | 583 |
| | 1,455 |
| | | 1,735 |
|
| Average interest rates, computed on a daily basis | 1.96 | % | | 1.23 | % | | | 0.94 | % |
| Average interest rates, at December 31 | 1.96 | % | | 1.23 | % | | | 1.14 | % |
|
| | | | | | | | | | | | |
| ComEd | | | | | | |
| | 2018 | | 2017 | | | 2016 |
| Average borrowings | $ | 154 |
| | $ | 200 |
| | | $ | 256 |
|
| Maximum borrowings outstanding | 520 |
| | 470 |
| | | 755 |
|
| Average interest rates, computed on a daily basis | 2.14 | % | | 1.24 | % | | | 0.77 | % |
| Average interest rates, at December 31 | 2.14 | % | | 1.24 | % | | | N/A |
|
| | | | | | | |
| PECO | | | | | | |
| | 2018 | | 2017 | | | 2016 |
| Average borrowings | $ | 68 |
| | $ | 2 |
| | | $ | — |
|
| Maximum borrowings outstanding | 350 |
| | 60 |
| | | — |
|
| Average interest rates, computed on a daily basis | 2.24 | % | | 1.13 | % | | | N/A |
|
| Average interest rates, at December 31 | 2.24 | % | | 1.13 | % | | | N/A |
|
| | | | | | | |
| BGE | | | | | | |
| | 2018 | | 2017 | | | 2016 |
| Average borrowings | $ | 65 |
| | $ | 54 |
| | | $ | 143 |
|
| Maximum borrowings outstanding | 239 |
| | 165 |
| | | 369 |
|
| Average interest rates, computed on a daily basis | 2.18 | % | | 1.28 | % | | | 0.77 | % |
| Average interest rates, computed at December 31 | 2.18 | % | | 1.28 | % | | | 0.95 | % |
| | | | | | | |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | |
| PHI Corporate | | | | | | |
| | 2018 | | 2017 | | | 2016 |
| Average borrowings | N/A |
| | N/A |
| | | $ | 153 |
|
| Maximum borrowings outstanding | N/A |
| | N/A |
| | | 559 |
|
| Average interest rates, computed on a daily basis | N/A |
| | N/A |
| | | 1.03 | % |
| Average interest rates, computed at December 31 | N/A |
| | N/A |
| | | N/A |
|
| | | | | | | |
| Pepco | | | | | | |
| | 2018 | | 2017 | | | 2016 |
| Average borrowings | $ | 22 |
| | $ | 51 |
| | | $ | 4 |
|
| Maximum borrowings outstanding | 90 |
| | 197 |
| | | 73 |
|
| Average interest rates, computed on a daily basis | 2.24 | % | | 1.06 | % | | | 0.71 | % |
| Average interest rates, computed at December 31 | 2.24 | % | | 1.06 | % | | | 0.90 | % |
| | | | | | | |
| DPL | | | | | | |
| | 2018 | | 2017 | | | 2016 |
| Average borrowings | $ | 87 |
| | $ | 40 |
| | | $ | 33 |
|
| Maximum borrowings outstanding | 245 |
| | 216 |
| | | 116 |
|
| Average interest rates, computed on a daily basis | 2.07 | % | | 1.48 | % | | | 0.68 | % |
| Average interest rates, computed at December 31 | 2.07 | % | | 1.48 | % | | | N/A |
|
| | | | | | | |
| ACE | | | | | | |
| | 2018 | | 2017 | | | 2016 |
| Average borrowings | $ | 95 |
| | $ | 30 |
| | | $ | — |
|
| Maximum borrowings outstanding | 210 |
| | 133 |
| | | 5 |
|
| Average interest rates, computed on a daily basis | 2.21 | % | | 1.43 | % | | | 0.65 | % |
| Average interest rates, computed at December 31 | 2.21 | % | | 1.43 | % | | | N/A |
|
Short-Term Loan Agreements
On January 13, 2016, PHI entered into a $500 million term loan agreement, which was amended on March 28, 2016. The net proceeds of the loan were used to repay PHI's outstanding commercial paper, and for general corporate purposes. Pursuant to the loan agreement, as amended, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1%, and all indebtedness thereunder is unsecured. On March 23, 2017, the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement was fully repaid and the loan terminated. On March 23, 2017, Exelon Corporate entered into a similar type term loan for $500 million which expired on March 22, 2018. The loan agreement was renewed on March 22, 2018 and will expire on March 21, 2019. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-Term borrowings.
On May 23, 2018, ACE entered into two term loan agreements in the aggregate amount of $125 million, which expire on May 22, 2019. Pursuant to the term loan agreements, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.55% and all indebtedness thereunder is unsecured.
Credit Agreements
On January 5, 2016, Generation entered into a credit agreement establishing a $150 million bilateral credit facility. On January 4, 2019, the credit agreement was amended to extend its maturity from January 2019 to April 2021.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
This facility will solely be utilized by Generation to issue lines of credit. This facility does not back Generation's commercial paper program.
On April 1, 2016, the credit agreement for CENG's $100 million bilateral credit facility was amended to increase the overall facility size to $200 million, scheduled to mature in October of 2019. This facility is utilized by CENG to fund working capital and capital projects. The facility does not back Generation's commercial paper program.
On May 26, 2016, Exelon Corporate, Generation, ComEd, PECO and BGE entered into amendments to each of their respective syndicated revolving credit facilities, which extended the maturity of each of the facilities to May 26, 2021. Exelon Corporate also increased the size of its facility from $500 million to $600 million. On May 26, 2016, PHI, Pepco, DPL and ACE entered into an amendment to their Second Amended and Restated Credit Agreement dated as of August 1, 2011, which (i) extended the maturity date of the facility to May 26, 2021, (ii) removed PHI as a borrower under the facility, (iii) decreased the size of the facility from $1.5 billion to $900 million and (iv) aligned its financial covenant from debt to capitalization leverage ratio to interest coverage ratio. (a)On May 26, 2018, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2023.
On January 9, 2017, the credit agreement for Generation's $75(b)Excludes $135 million bilateralof credit facility was amendedagreements arranged at minority and restated to increase the facility size to $100 million. On January 4, 2019, the credit agreement was amended to extend its maturity from January 2019 to Marchcommunity banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $38 million, $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. These facilities expire on October 8, 2021. This facility willThese facilities are solely be used by Generationutilized to issue letters of credit. As of December 31, 2020, letters of credit issued under these facilities totaled $5 million, $5 million, and $2 million for Generation, ComEd, and BGE, respectively.
(c)Includes $600 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $6 million outstanding letters of credit at December 31, 2020. Exelon Corporate had $594 million in available capacity to support additional commercial paper at December 31, 2020.
On March 15,19, 2020, Generation borrowed $1.5 billion on its revolving credit facility due to disruptions in the commercial paper markets as a result of COVID-19. The funds were used to refinance commercial paper. Generation repaid the $1.5 billion borrowed on the revolving credit facility on April 3, 2020.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a 12-month term loan agreement for $500 million, which was renewed annually on March 22, 2018, March 20, 2019, and March 19, 2020, respectively. The loan agreement will expire on March 18, 2021. Pursuant to the loan agreement, as of December 31, 2020, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loans beared interest at LIBOR plus 0.95% as of December 31, 2019 as part of the March 20, 2019 renewal. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.
On March 19, 2020, Generation entered into a term loan agreement for $200 million. The loan agreement has an expiration of March 18, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.50% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.
On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement has an expiration of March 30, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.75% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
On January 25, 2021, ComEd entered into two 90-day term loan agreements of $125 million each with variable interest rates of LIBOR plus 0.50% and LIBOR plus 0.75%, respectively.
Revolving Credit Agreements
On April 24, 2020, Exelon Corporate entered into a credit agreement forestablishing a Generation bilateral$550 million 364-day revolving credit facility at a variable interest rate of $30 million was amended to increase the overall facility size to $95 million, scheduled to mature in March of 2020.LIBOR plus 1.75%. This facility will solely be used by Exelon as an additional source of short-term liquidity as needed.
Bilateral Credit Agreements
The following table reflects the bilateral credit agreements at December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant | | Date Initiated | | Latest Amendment Date | | Maturity Date(a) | | Amount |
Generation(b) | | October 26, 2012 | | October 23, 2020 | | October 22, 2021 | | $ | 200 | |
Generation(c) | | January 11, 2013 | | January 4, 2019 | | March 1, 2021 | | 100 |
Generation(c) | | January 5, 2016 | | January 4, 2019 | | April 5, 2021 | | 150 |
Generation(c) | | February 21, 2019 | | N/A | | March 31, 2021 | | 100 |
Generation(c) | | October 25, 2019 | | N/A | | N/A | | 200 |
Generation(c) | | October 25, 2019 | | N/A | | N/A | | 100 |
Generation(c) | | November 20, 2019 | | N/A | | N/A | | 300 |
Generation(c) | | November 21, 2019 | | N/A | | N/A | | 150 |
Generation(c) | | November 21, 2019 | | N/A | | November 21, 2021 | | 100 |
Generation(c) | | May 15, 2020 | | N/A | | N/A | | 100 |
__________
(a)Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement.
(b)Bilateral credit facility relates to CENG, which is incorporated within Generation, to issueand supports the issuance of letters of credit.credit and funding for working capital and does not back Generation's commercial paper program. During the second and third quarters of 2020, CENG drew on its bilateral credit facility. As of December 31, 2020, there was 0 outstanding balance at this facility.
(c)Bilateral credit agreements solely support the issuance of letters of credit and do not back Generation's commercial paper program.
Borrowings under Exelon Corporate’s,Exelon’s, Generation’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon(a) | | Generation | | ComEd | | PECO | | BGE | | | | Pepco | | DPL | | ACE |
| Prime based borrowings | 0 - 27.5 | | 27.5 | | | — | | | — | | | — | | | | | 7.5 | | | — | | | 7.5 | |
| LIBOR-based borrowings | 90.0 - 127.5 | | 127.5 | | | 100.0 | | | 90.0 | | | 90.0 | | | | | 107.5 | | | 100.0 | | | 107.5 | |
|
| | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
| Prime based borrowings | 27.5 | | 27.5 | | 7.5 | | — | | — | | 7.5 | | 7.5 | | 7.5 |
| LIBOR-based borrowings | 127.5 | | 127.5 | | 107.5 | | 90.0 | | 100.0 | | 107.5 | | 107.5 | | 107.5 |
The(a)Includes interest rate adders at Exelon Corporate of 27.5 and 127.5 for prime and LIBOR-based borrowings, respectively.
If any registrant loses its investment grade rating, the maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 90would be 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower.
Each revolving credit agreement for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2018:
|
| | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
Credit agreement threshold | 2.50 to 1 | | 3.00 to 1 | | 2.00 to 1 | | 2.00 to 1 | | 2.00 to 1 | | 2.00 to 1 | | 2.00 to 1 | | 2.00 to 1 |
At December 31, 2018, the interest coverage ratios at the Registrants were as follows:
|
| | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
| Interest coverage ratio | 7.34 | | 10.99 | | 7.34 | | 8.14 | | 9.77 | | 5.98 | | 7.03 | | 5.06 |
An event of default under Exelon, Generation, ComEd, PECO or BGE's indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
will constitute an event of default under the Exelon Corporate credit facility. An event of default under Pepco, DPL or ACE's indebtedness will not constitute an event of default with respect to the other PHI Utilities under the PHI Utilities' combined credit facility.
The absence of a material adverse change in Exelon's or PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under any of the borrowers' credit agreement. None of the credit agreements include any rating triggers.
Variable Rate Demand BondsComponents of Income Tax Expense or Benefit
DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demandIncome tax expense (benefit) from continuing operations is comprised of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. PHI expects that any bonds submitted for purchase will be remarketed successfully due to the creditworthinessfollowing components:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2020 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Included in operations: | | | | | | | | | | | | | | | | | |
| Federal | | | | | | | | | | | | | | | | | |
| Current | $ | 26 | | | $ | 130 | | | $ | (24) | | | $ | (7) | | | $ | 4 | | | $ | 25 | | | $ | 40 | | | $ | (13) | | | $ | (4) | |
| Deferred | 156 | | | 150 | | | 112 | | | 1 | | | 10 | | | (129) | | | (62) | | | (20) | | | (43) | |
| Investment tax credit amortization | (28) | | | (25) | | | (2) | | | 0 | | | 0 | | | (1) | | | 0 | | | 0 | | | 0 | |
| State | | | | | | | | | | | | | | | | | |
| Current | 42 | | | 40 | | | (27) | | | 0 | | | 0 | | | (5) | | | 0 | | | 0 | | | 0 | |
| Deferred | 177 | | | (46) | | | 118 | | | (24) | | | 27 | | | 33 | | | 15 | | | 8 | | | 6 | |
| Total | $ | 373 | | | $ | 249 | | | $ | 177 | | | $ | (30) | | | $ | 41 | | | $ | (77) | | | $ | (7) | | | $ | (25) | | | $ | (41) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2019 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Included in operations: | | | | | | | | | | | | | | | | | |
| Federal | | | | | | | | | | | | | | | | | |
| Current | $ | 85 | | | $ | 147 | | | $ | 59 | | | $ | 45 | | | $ | (51) | | | $ | 43 | | | $ | 16 | | | $ | 29 | | | $ | (3) | |
| Deferred | 489 | | | 346 | | | 15 | | | 20 | | | 95 | | | (34) | | | (6) | | | (21) | | | (6) | |
| Investment tax credit amortization | (72) | | | (69) | | | (2) | | | 0 | | | 0 | | | (1) | | | 0 | | | 0 | | | 0 | |
| State | | | | | | | | | | | | | | | | | |
| Current | 5 | | | 10 | | | (5) | | | 0 | | | 0 | | | 3 | | | 0 | | | 0 | | | 0 | |
| Deferred | 267 | | | 82 | | | 96 | | | 0 | | | 35 | | | 27 | | | 6 | | | 14 | | | 9 | |
| Total | $ | 774 | | | $ | 516 | | | $ | 163 | | | $ | 65 | | | $ | 79 | | | $ | 38 | | | $ | 16 | | | $ | 22 | | | $ | 0 | |
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
Long-Term Debt | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2018 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Included in operations: | | | | | | | | | | | | | | | | | |
| Federal | | | | | | | | | | | | | | | | | |
| Current | $ | 226 | | | $ | 337 | | | $ | (63) | | | $ | 11 | | | $ | (5) | | | $ | (4) | | | $ | 28 | | | $ | (3) | | | $ | (14) | |
| Deferred | (99) | | | (347) | | | 145 | | | 10 | | | 47 | | | 23 | | | (22) | | | 13 | | | 18 | |
| Investment tax credit amortization | (24) | | | (21) | | | (2) | | | 0 | | | 0 | | | (1) | | | 0 | | | 0 | | | 0 | |
| State | | | | | | | | | | | | | | | | | |
| Current | (1) | | | 6 | | | (29) | | | 1 | | | 0 | | | 7 | | | 0 | | | 0 | | | 0 | |
| Deferred | 16 | | | (83) | | | 117 | | | (16) | | | 32 | | | 8 | | | 5 | | | 12 | | | 8 | |
| Total | $ | 118 | | | $ | (108) | | | $ | 168 | | | $ | 6 | | | $ | 74 | | | $ | 33 | | | $ | 11 | | | $ | 22 | | | $ | 12 | |
Rate Reconciliation
The following tables presenteffective income tax rate from continuing operations varies from the outstanding long-term debt atU.S. federal statutory rate principally due to the Registrants asfollowing:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2020(a) |
| Exelon | | Generation | | ComEd(b) | | PECO(c) | | BGE(d) | | PHI(d) | | Pepco(d) | | DPL(d) | | ACE(d) |
| U.S. federal statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
| State income taxes, net of Federal income tax benefit | 7.8 | | | 0.5 | | | 11.6 | | | (4.5) | | | 5.5 | | | 5.1 | | | 4.5 | | | 6.6 | | | 7.0 | |
| Qualified NDT fund income | 8.4 | | | 23.5 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred Prosecution Agreement payments | 1.8 | | | 0 | | | 6.8 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.1) | | | (2.6) | | | (0.3) | | | 0 | | | (0.1) | | | (0.2) | | | (0.1) | | | (0.3) | | | (0.5) | |
| Plant basis differences | (4.0) | | | 0 | | | (0.6) | | | (18.7) | | | (1.5) | | | (1.6) | | | (1.7) | | | (0.4) | | | (3.0) | |
| Production tax credits and other credits | (2.2) | | | (5.4) | | | (0.3) | | | 0 | | | (0.4) | | | (0.3) | | | (0.3) | | | (0.3) | | | (0.5) | |
| Noncontrolling interests | 1.1 | | | 3.2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Excess deferred tax amortization | (13.6) | | | 0 | | | (11.2) | | | (4.6) | | | (13.9) | | | (42.0) | | | (25.4) | | | (51.7) | | | (82.1) | |
| Tax settlements | (3.7) | | | (10.3) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Other | 0.5 | | | (0.1) | | | 1.8 | | | (0.4) | | | (0.1) | | | (0.4) | | | (0.7) | | | 0.1 | | | 0.4 | |
| Effective income tax rate | 16.0 | % | | 29.8 | % | | 28.8 | % | | (7.2) | % | | 10.5 | % | | (18.4) | % | | (2.7) | % | | (25.0) | % | | (57.7) | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2019(a) |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| U.S. federal statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
| State income taxes, net of Federal income tax benefit | 5.4 | | | 3.8 | | | 8.5 | | | 0 | | | 6.4 | | | 4.7 | | | 2.0 | | | 6.8 | | | 7.0 | |
| Qualified NDT fund income | 5.9 | | | 12.3 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.5) | | | (3.0) | | | (0.2) | | | 0 | | | (0.1) | | | (0.2) | | | (0.1) | | | (0.2) | | | (0.3) | |
| Plant basis differences | (1.4) | | | 0 | | | 0 | | | (7.2) | | | (1.2) | | | (1.2) | | | (1.8) | | | (0.4) | | | (0.7) | |
| Production tax credits and other credits | (3.1) | | | (4.8) | | | (1.2) | | | 0 | | | (1.3) | | | (0.2) | | | (0.1) | | | 0 | | | (0.1) | |
| Noncontrolling interests | (0.6) | | | (1.2) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Excess deferred tax amortization | (5.5) | | | 0 | | | (9.7) | | | (2.8) | | | (6.8) | | | (17.5) | | | (15.1) | | | (14.2) | | | (27.0) | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Other | (0.8) | | | (1.2) | | | 0.8 | | | 0 | | | 0 | | | 0.8 | | | 0.3 | | | 0 | | | 0.1 | |
| Effective income tax rate | 19.4 | % | | 26.9 | % | | 19.2 | % | | 11.0 | % | | 18.0 | % | | 7.4 | % | | 6.2 | % | | 13.0 | % | | 0 | % |
Exelon
|
| | | | | | | | | | | | | | | | |
| | | | | | Maturity Date | | December 31, |
| | Rates | | 2018 | | 2017 |
| Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 1.70 | % | - | 7.90 | % | | 2019 - 2048 | | 16,496 |
| | 15,197 |
|
| Senior unsecured notes | 2.45 | % | - | 7.60 | % | | 2019 - 2046 | | 11,285 |
| | 11,285 |
|
| Unsecured notes | 2.40 | % | - | 6.35 | % | | 2021 - 2048 | | 2,900 |
| | 2,600 |
|
| Pollution control notes | 2.50 | % | - | 2.70 | % | | 2025 - 2036 | | 435 |
| | 435 |
|
| Nuclear fuel procurement contracts | | | 3.15 | % | | 2020 | | 39 |
| | 82 |
|
Notes payable and other(b)(c) | 2.85 | % | - | 8.88 | % | | 2019 - 2053 | | 188 |
| | 405 |
|
| Junior subordinated notes |
| | 3.50 | % | | 2022 | | 1,150 |
| | 1,150 |
|
| Long-term software licensing agreement | | | 3.95 | % | | 2024 | | 73 |
| | 79 |
|
| Unsecured Tax-Exempt Bonds | 1.74 | % | - | 5.40 | % | — |
| 2024 - 2031 | | 112 |
| | 112 |
|
| Medium-Terms Notes (unsecured) | 7.61 | % | - | 7.72 | % | | 2019 - 2027 | | 22 |
| | 26 |
|
| Transition bonds | | | 5.55 | % | | 2023 | | 59 |
| | 90 |
|
| Loan Agreement | | | 2.00 | % | | 2023 | | 50 |
| | — |
|
| Nonrecourse debt: | | | | | | | | | |
| Fixed rates | 2.29 | % | - | 6.00 | % | | 2031 - 2037 | | 1,253 |
| | 1,331 |
|
Variable rates(f) |
|
| | 5.81 | % | | 2019 - 2024 | | 849 |
| | 865 |
|
| Total long-term debt | | | | | | | 34,911 |
| | 33,657 |
|
| Unamortized debt discount and premium, net | | | | | | | (66 | ) | | (57 | ) |
| Unamortized debt issuance costs | | | | | | | (216 | ) | | (201 | ) |
| Fair value adjustment | | | | | | | 795 |
| | 865 |
|
Long-term debt due within one year(e) | | | | | | | (1,349 | ) | | (2,088 | ) |
| Long-term debt | | | | | | | $ | 34,075 |
| | $ | 32,176 |
|
Long-term debt to financing trusts(d) | | | | | | | | | |
| Subordinated debentures to ComEd Financing III | | | 6.35 | % | | 2033 | | $ | 206 |
| | $ | 206 |
|
| Subordinated debentures to PECO Trust III | 7.38 | % | - | 7.50 | % | | 2028 | | 81 |
| | 81 |
|
| Subordinated debentures to PECO Trust IV | | | 5.75 | % | | 2033 | | 103 |
| | 103 |
|
| Total long-term debt to financing trusts | | | | | | | 390 |
| | 390 |
|
| Unamortized debt issuance costs | | | | | | | — |
| | (1 | ) |
| Long-term debt to financing trusts | | | | | | | $ | 390 |
| | $ | 389 |
|
__________
| |
(a) | Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's and ACE's assets are subject to the liens of their respective mortgage indentures. |
| |
(b) | Includes capital lease obligations of $36 million and $53 million at December 31, 2018 and 2017, respectively. Lease payments of $21 million, $5 million, $1 million, $1 million, less than $1 million, and $8 million will be made in 2019, 2020, 2021, 2022, 2023, and thereafter, respectively. |
| |
(c) | Includes financing related to Albany Green Energy, LLC (AGE). During the third quarter of 2017, Generation retired $228 million of its outstanding debt balance. |
| |
(d) | Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets. |
| |
(e) | In January 2019, $300 million of ComEd long-term debt due within one year was paid in full. |
| |
(f) | Excludes interest on CEU Upstream nonrecourse debt, see discussion below. |
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation
|
| | | | | | | | | | | | | | | |
| | | | | | Maturity Date | | December 31, |
| | Rates | | 2018 | | 2017 |
| Long-term debt | | | | | | | | | |
| Senior unsecured notes | 2.95 | % | - | 7.60 | % | | 2019 - 2042 | | $ | 6,019 |
| | $ | 6,019 |
|
| Pollution control notes | 2.50 | % | - | 2.70 | % | | 2025 - 2036 | | 435 |
| | 435 |
|
| Nuclear fuel procurement contracts | |
| 3.15 | % | | 2020 | | 39 |
| | 82 |
|
Notes payable and other(a)(b) | 2.85 | % | - | 7.83 | % | | 2019 - 2024 | | 164 |
| | 223 |
|
| Nonrecourse debt: | | | | | | | | | |
| Fixed rates | 2.29 | % | - | 6.00 | % | | 2031 - 2037 | | 1,253 |
| | 1,331 |
|
Variable rates(c) | |
| 5.81 | % | | 2019 - 2024 | | 849 |
| | 865 |
|
| Total long-term debt | | | | | | | 8,759 |
| | 8,955 |
|
| Unamortized debt discount and premium, net | | | | | | | (6 | ) | | (8 | ) |
| Unamortized debt issuance costs | | | | | | | (51 | ) | | (60 | ) |
| Fair value adjustment | | | | | | | 91 |
| | 103 |
|
| Long-term debt due within one year | | | | | | | (906 | ) | | (346 | ) |
| Long-term debt | | | | | | | $ | 7,887 |
| | $ | 8,644 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2018(a) |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| U.S. federal statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
| State income taxes, net of Federal income tax benefit | 0.5 | | | (16.6) | | | 8.3 | | | (2.6) | | | 6.6 | | | 2.9 | | | 2.0 | | | 6.7 | | | 7.4 | |
| Qualified NDT fund income | (1.9) | | | (11.8) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.2) | | | (6.5) | | | (0.2) | | | (0.1) | | | (0.1) | | | (0.2) | | | (0.1) | | | (0.3) | | | (0.4) | |
| Plant basis differences | (3.5) | | | 0 | | | (0.2) | | | (14.1) | | | (1.3) | | | (1.6) | | | (2.8) | | | (0.3) | | | (0.5) | |
| Production tax credits and other credits | (2.2) | | | (13.5) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Noncontrolling interests | (1.0) | | | (6.1) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Excess deferred tax amortization | (8.3) | | | 0 | | | (9.1) | | | (3.2) | | | (8.0) | | | (14.8) | | | (15.3) | | | (12.0) | | | (14.9) | |
| Tax Cuts and Jobs Act of 2017 | 0.9 | | | 2.7 | | | (0.1) | | | 0 | | | 0 | | | 0.1 | | | 0 | | | 0 | | | 0 | |
| Other | 1.0 | | | 1.3 | | | 0.5 | | | 0.3 | | | 0.9 | | | 0.4 | | | 0.3 | | | 0.4 | | | 1.2 | |
| Effective income tax rate | 5.3 | % | | (29.5) | % | | 20.2 | % | | 1.3 | % | | 19.1 | % | | 7.8 | % | | 5.1 | % | | 15.5 | % | | 13.8 | % |
__________
| |
(a) | Includes Generation’s capital lease obligations of $14 million and $18 million at December 31, 2018 and 2017, respectively. Generation will make lease payments of $7 million, $5 million, $1 million, and $1 million in 2019, 2020, 2021, and 2022, respectively. Lease payments of less than $1 million annually will be made from 2023 through expiration of the final capital lease in 2024. |
| |
(b) | Includes financing related to Albany Green Energy, LLC (AGE). During the third quarter of 2017, Generation retired $228 million of its outstanding debt balance. |
| |
(c) | Excludes interest on CEU Upstream nonrecourse debt, see discussion below. |
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. See Note 19 — Commitments and Contingencies for additional information.
(c)At PECO, the negative effective tax rate is primarily related to an increase in plant basis differences attributable to tax repair deductions related to an increase in storms and qualifying projects.
(d)At BGE, the lower effective tax rate, and at PHI, Pepco, DPL, and ACE, the negative effective tax rate is primarily attributable to accelerated amortization of transmission related income tax regulatory liabilities as a result of regulatory settlements. See Note 3 — Regulatory Matters for additional information.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd
|
| | | | | | | | | | | | | | | |
| | | | | | Maturity Date | | December 31, |
| | Rates | | 2018 | | 2017 |
| Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 2.15 | % | - | 6.45 | % | | 2019 - 2048 | | $ | 8,179 |
| | $ | 7,529 |
|
Notes payable and other(b) |
|
| | 7.49 | % | | 2053 | | 8 |
| | 147 |
|
| Total long-term debt | | | | | | | 8,187 |
| | 7,676 |
|
| Unamortized debt discount and premium, net | | | | | | | (23 | ) | | (23 | ) |
| Unamortized debt issuance costs | | | | | | | (63 | ) | | (52 | ) |
Long-term debt due within one year(d) | | | | | | | (300 | ) | | (840 | ) |
| Long-term debt | | | | | | | $ | 7,801 |
| | $ | 6,761 |
|
Long-term debt to financing trust(c) | | | | | | | | | |
| Subordinated debentures to ComEd Financing III | | | 6.35 | % | | 2033 | | $ | 206 |
| | $ | 206 |
|
| Total long-term debt to financing trusts | | | | | | | 206 |
| | 206 |
|
| Unamortized debt issuance costs | | | | | | | (1 | ) | | (1 | ) |
| Long-term debt to financing trusts | | | | | | | $ | 205 |
| | $ | 205 |
|
The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2020 and 2019 are presented below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2020 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Plant basis differences | $ | (13,868) | | | $ | (2,592) | | | $ | (4,432) | | | $ | (2,131) | | | $ | (1,711) | | | $ | (2,822) | | | $ | (1,259) | | | $ | (806) | | | $ | (725) | |
| Accrual based contracts | 40 | | | (37) | | | 0 | | | 0 | | | 0 | | | 77 | | | 0 | | | 0 | | | 0 | |
| Derivatives and other financial instruments | 41 | | | (41) | | | 84 | | | 0 | | | 0 | | | 2 | | | 0 | | | 0 | | | 0 | |
| Deferred pension and postretirement obligation | 1,559 | | | (236) | | | (288) | | | (30) | | | (33) | | | (80) | | | (74) | | | (40) | | | (7) | |
| Nuclear decommissioning activities | (742) | | | (742) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred debt refinancing costs | 169 | | | 16 | | | (6) | | | 0 | | | (2) | | | 131 | | | (3) | | | (1) | | | (1) | |
| Regulatory assets and liabilities | (1,107) | | | 0 | | | 87 | | | (231) | | | 142 | | | (41) | | | 38 | | | 67 | | | 46 | |
| Tax loss carryforward | 286 | | | 55 | | | 0 | | | 47 | | | 57 | | | 90 | | | 4 | | | 49 | | | 38 | |
| Tax credit carryforward | 841 | | | 838 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Investment in partnerships | (835) | | | (813) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Other, net | 1,070 | | | 347 | | | 223 | | | 104 | | | 29 | | | 220 | | | 107 | | | 18 | | | 27 | |
| Deferred income tax liabilities (net) | $ | (12,546) | | | $ | (3,205) | | | $ | (4,332) | | | $ | (2,241) | | | $ | (1,518) | | | $ | (2,423) | | | $ | (1,187) | | | $ | (713) | | | $ | (622) | |
Unamortized investment tax credits(a) | (464) | | | (445) | | | (9) | | | (1) | | | (3) | | | (6) | | | (2) | | | (2) | | | (3) | |
| Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (13,010) | | | $ | (3,650) | | | $ | (4,341) | | | $ | (2,242) | | | $ | (1,521) | | | $ | (2,429) | | | $ | (1,189) | | | $ | (715) | | | $ | (625) | |
__________
| |
(a) | Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture. |
| |
(b) | Includes ComEd’s capital lease obligations of $8 million at both December 31, 2018 and 2017, respectively. Lease payments of less than $1 million annually will be made from 2019 through expiration at 2053. |
| |
(c) | Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets. |
| |
(d) | In January 2019, the $300 million balance was paid in full. |
PECO(a)Does not include unamortized investment tax credits reclassified to liabilities held for sale.
|
| | | | | | | | | | | | | | | |
| | | | | | Maturity Date | | December 31, |
| | Rates | | 2018 | | 2017 |
| Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 1.70 | % | - | 5.95 | % | | 2021 - 2048 | | $ | 3,075 |
| | $ | 2,925 |
|
| Loan Agreement | | | 2.00 | % | | 2023 | | 50 |
| | 0 |
|
| Total long-term debt | | | | | | | 3,125 |
| | 2,925 |
|
| Unamortized debt discount and premium, net | | | | | | | (18 | ) | | (5 | ) |
| Unamortized debt issuance costs | | | | | | | (23 | ) | | (17 | ) |
| Long-term debt due within one year | | | | | | | — |
| | (500 | ) |
| Long-term debt | | | | | | | $ | 3,084 |
| | $ | 2,403 |
|
Long-term debt to financing trusts(b) | | | | | | | | | |
| Subordinated debentures to PECO Trust III | 7.38 | % | - | 7.50 | % | | 2028 | | $ | 81 |
| | $ | 81 |
|
| Subordinated debentures to PECO Trust IV | | | 5.75 | % | | 2033 | | 103 |
| | 103 |
|
| Long-term debt to financing trusts | | | | | | | $ | 184 |
| | $ | 184 |
|
__________
| |
(a) | Substantially all of PECO’s assets are subject to the lien of its mortgage indenture. |
| |
(b) | Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
BGE
|
| | | | | | | | | | | | | | | |
| | | | | | Maturity Date | | December 31, |
| | Rates | | 2018 | | 2017 |
| Long-term debt | | | | | | | | | |
| Unsecured notes | 2.40 | % | - | 6.35 | % | | 2021 - 2048 | | 2,900 |
| | 2,600 |
|
| Total long-term debt | | | | | | | 2,900 |
| | 2,600 |
|
| Unamortized debt discount and premium, net | | | | | | | (6 | ) | | (6 | ) |
| Unamortized debt issuance costs | | | | | | | (18 | ) | | (17 | ) |
| Long-term debt | | | | | | | $ | 2,876 |
| | $ | 2,577 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2019 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Plant basis differences | $ | (13,413) | | | $ | (2,814) | | | $ | (4,197) | | | $ | (1,978) | | | $ | (1,578) | | | $ | (2,681) | | | $ | (1,204) | | | $ | (753) | | | $ | (687) | |
| Accrual based contracts | 61 | | | (43) | | | 0 | | | 0 | | | 0 | | | 104 | | | 0 | | | 0 | | | 0 | |
| Derivatives and other financial instruments | 165 | | | 88 | | | 84 | | | 0 | | | 0 | | | 2 | | | 0 | | | 0 | | | 0 | |
| Deferred pension and postretirement obligation | 1,504 | | | (220) | | | (270) | | | (28) | | | (28) | | | (89) | | | (75) | | | (42) | | | (10) | |
| Nuclear decommissioning activities | (503) | | | (503) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred debt refinancing costs | 183 | | | 20 | | | (7) | | | 0 | | | (3) | | | 142 | | | (3) | | | (2) | | | (1) | |
| Regulatory assets and liabilities | (884) | | | 0 | | | 183 | | | (169) | | | 157 | | | (10) | | | 55 | | | 88 | | | 77 | |
| Tax loss carryforward | 240 | | | 55 | | | 0 | | | 25 | | | 49 | | | 93 | | | 13 | | | 44 | | | 31 | |
| Tax credit carryforward | 892 | | | 897 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Investment in partnerships | (830) | | | (808) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Other, net | 926 | | | 236 | | | 196 | | | 70 | | | 10 | | | 181 | | | 85 | | | 12 | | | 16 | |
| Deferred income tax liabilities (net) | $ | (11,659) | | | $ | (3,092) | | | $ | (4,011) | | | $ | (2,080) | | | $ | (1,393) | | | $ | (2,258) | | | $ | (1,129) | | | $ | (653) | | | $ | (574) | |
| Unamortized investment tax credits | (668) | | | (648) | | | (10) | | | (1) | | | (3) | | | (7) | | | (2) | | | (2) | | | (3) | |
Total deferred income tax liabilities (net) and
unamortized investment tax credits | $ | (12,327) | | | $ | (3,740) | | | $ | (4,021) | | | $ | (2,081) | | | $ | (1,396) | | | $ | (2,265) | | | $ | (1,131) | | | $ | (655) | | | $ | (577) | |
PHIThe following table provides Exelon’s, Generation’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s, and ACE’s carryforwards, which are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2020. ComEd does not have net operating losses or credit carryforwards for the year ended December 31, 2020.
|
| | | | | | | | | | | | | | | |
| | | | | | Maturity
Date | | December 31, |
| | Rates | | 2018 | | 2017 |
| Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 1.81 | % | - | 7.90 | % | | 2021 - 2048 | | $ | 5,242 |
| | $ | 4,743 |
|
| Senior unsecured notes | |
| 7.45 | % | | 2032 | | 185 |
| | 185 |
|
| Unsecured Tax-Exempt Bonds | 1.74 | % | - | 5.40 | % | | 2024 - 2031 | | 112 |
| | 112 |
|
| Medium-terms notes (unsecured) | 7.61 | % | - | 7.72 | % | | 2019 - 2027 | | 22 |
| | 26 |
|
Transition bonds(b) |
|
|
| 5.55 | % | | 2023 | | 59 |
| | 90 |
|
Notes payable and other (c) | 7.28 | % | - | 8.88 | % | | 2019 - 2022 | | 16 |
| | 33 |
|
| Total long-term debt | | | | | | | 5,636 |
|
| 5,189 |
|
| Unamortized debt discount and premium, net | | | | | | | 4 |
| | 5 |
|
| Unamortized debt issuance costs | | | | | | | (14 | ) | | (6 | ) |
| Fair value adjustment | | | | | | | 633 |
| | 686 |
|
| Long-term debt due within one year | | | | | | | (125 | ) | | (396 | ) |
| Long-term debt | | | | | | | $ | 6,134 |
|
| $ | 5,478 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Federal | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Federal general business credits carryforwards and other carryforwards | $ | 858 | | | $ | 852 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| State | | | | | | | | | | | | | | | |
| State net operating losses and other carryforwards | 5,202 | | | 1,118 | | | 616 | | | 902 | | | 1,436 | | | 63 | | | 728 | | | 531 | |
| Deferred taxes on state tax attributes (net) | 324 | | | 76 | | | 49 | | | 59 | | | 98 | | | 4 | | | 49 | | | 38 | |
| Valuation allowance on state tax attributes | 27 | | | 23 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Year in which net operating loss or credit carryforwards will begin to expire(a) | 2034 | | 2034 | | 2032 | | 2033 | | 2029 | | 2029 | | 2032 | | 2031 |
__________
| |
(a) | Substantially all of Pepco's, DPL's, and ACE's assets are subject to the lien of its respective mortgage indenture. |
| |
(b) | Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets. |
| |
(c) | Includes Pepco's capital lease obligations of $14 million and $27 million at December 31, 2018 and 2017, respectively. |
(a)Generation's state net operating loss carryforwards will begin expiring in 2029. PECO's Pennsylvania charitable contribution carryforwards and BGE's Maryland charitable deduction and capital loss carryforwards will begin expiring in 2021. ACE's New Jersey tax credit carryforward has an indefinite carryforward period. These amounts are not material.
Tabular Reconciliation of Unrecognized Tax Benefits
The following table presents changes in unrecognized tax benefits, by Registrant.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pepco
|
| | | | | | | | | | | | | | | |
| | | | | | Maturity
Date | | December 31, |
| | Rates | | 2018 | | 2017 |
| Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 3.05 | % | - | 7.90 | % | | 2022 - 2048 | | $ | 2,735 |
| | $ | 2,535 |
|
Notes payable and other(b) | 7.28 | % | - | 8.88 | % | | 2019 - 2022 | | 16 |
| | 35 |
|
| Total long-term debt | | | | | | | 2,751 |
|
| 2,570 |
|
| Unamortized debt discount and premium, net | | | | | | | 2 |
| | 2 |
|
| Unamortized debt issuance costs | | | | | | | (34 | ) | | (32 | ) |
| Long-term debt due within one year | | | | | | | (15 | ) | | (19 | ) |
| Long-term debt | | | | | | | $ | 2,704 |
|
| $ | 2,521 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance at January 1, 2018 | $ | 743 | | | $ | 468 | | | $ | 2 | | | $ | 0 | | | $ | 120 | | | $ | 125 | | | $ | 59 | | | $ | 21 | | | $ | 14 | |
| Change to positions that only affect timing | 15 | | | 15 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Increases based on tax positions prior to 2018 | 30 | | | 21 | | | 0 | | | 0 | | | 0 | | | 8 | | | 7 | | | 1 | | | 0 | |
Decreases based on tax positions prior to 2018(a) | (251) | | | (36) | | | 0 | | | 0 | | | (120) | | | (88) | | | (66) | | | (22) | | | 0 | |
| Decrease from settlements with taxing authorities | (53) | | | (53) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Decreases from expiration of statute of limitations | (7) | | | (7) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance at December 31, 2018 | 477 | | | 408 | | | 2 | | | 0 | | | 0 | | | 45 | | | 0 | | | 0 | | | 14 | |
| Change to positions that only affect timing | 26 | | | 12 | | | 3 | | | 1 | | | 4 | | | 3 | | | 2 | | | 1 | | | 0 | |
| Increases based on tax positions related to 2019 | 2 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Increases based on tax positions prior to 2019 | 34 | | | 19 | | | 3 | | | 2 | | | 3 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Decreases based on tax positions prior to 2019 | (3) | | | (3) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Decrease from settlements with taxing authorities | (29) | | | 4 | | | (2) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance at December 31, 2019 | 507 | | | 441 | | | 6 | | | 3 | | | 7 | | | 48 | | | 2 | | | 1 | | | 14 | |
| Change to positions that only affect timing | 6 | | | 0 | | | 2 | | | 3 | | | 3 | | | 3 | | | 1 | | | 0 | | | 1 | |
| Increases based on tax positions related to 2020 | 3 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Increases based on tax positions prior to 2020 | 26 | | | 23 | | | 1 | | | 0 | | | 0 | | | 1 | | | 0 | | | 0 | | | 0 | |
Decreases based on tax positions prior to 2020(b) | (348) | | | (346) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Decrease from settlements with taxing authorities(b) | (69) | | | (69) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Balance at December 31, 2020 | $ | 125 | | | $ | 50 | | | $ | 9 | | | $ | 6 | | | $ | 10 | | | $ | 52 | | | $ | 3 | | | $ | 1 | | | $ | 15 | |
__________
| |
(a) | Substantially all of Pepco's assets are subject(a)Exelon, Generation, BGE, PHI, Pepco, and DPL decreased their unrecognized state tax benefits primarily due to the receipt of favorable guidance with respect to the deductibility of certain depreciable fixed assets. The recognition of the tax benefits related to BGE, PHI, Pepco, and DPL was offset by corresponding regulatory liabilities and that portion had no immediate impact to their effective tax rate. (b)Exelon's and Generation's unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $411 million due to the settlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase to Exelon's and Generation’s net income of $76 million and $73 million, respectively, in the first quarter of 2020, reflecting a decrease to Exelon's and Generation's income tax expense of $67 million. Like-Kind Exchange In 2016, the Tax Court held that Exelon was not entitled to defer a gain on its 1999 like-kind exchange transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for penalties and interest on the penalties. Exelon had fully paid the amounts assessed resulting from the Tax Court decision in 2017. In September 2017, Exelon appealed the Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the lien of its respective mortgage indenture. |
| |
(b) | Includes capital lease obligations of $14 million and $27 million at December 31, 2018 and 2017, respectively. Lease payments of $14 million will be made in 2019. |
DPL
|
| | | | | | | | | | | | | | | |
| | | | | | Maturity
Date | | December 31, |
| | Rates | | 2018 | | 2017 |
| Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 1.81 | % | - | 4.27 | % | | 2023 - 2048 | | $ | 1,370 |
| | $ | 1,171 |
|
| Unsecured Tax-Exempt Bonds | 1.74 | % | - | 5.40 | % | | 2024 - 2031 | | 112 |
| | 112 |
|
| Medium-terms notes (unsecured) | 7.61 | % | - | 7.72 | % | | 2019 - 2027 | | 22 |
| | 26 |
|
| Total long-term debt | | | | | | | 1,504 |
|
| 1,309 |
|
| Unamortized debt discount and premium, net | | | | | | | 2 |
| | 2 |
|
| Unamortized debt issuance costs | | | | | | | (12 | ) | | (11 | ) |
| Long-term debt due within one year | | | | | | | (91 | ) | | (83 | ) |
| Long-term debt | | | | | | | $ | 1,403 |
|
| $ | 1,217 |
|
__________
| |
(a) | Substantially all of DPL's assets are subject to the lien of its respective mortgage indenture. |
ACE
|
| | | | | | | | | | | | | | | |
| | | | | | Maturity
Date | | December 31, |
| | Rates | | 2018 | | 2017 |
| Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 3.38 | % | - | 6.80 | % | | 2021 - 2036 | | $ | 1,137 |
| | $ | 1,037 |
|
Transition bonds(b) |
| | 5.55 | % | | 2023 | | 59 |
| | 90 |
|
| Total long-term debt | | | | | | | 1,196 |
|
| 1,127 |
|
| Unamortized debt discount and premium, net | | | | | | | (1 | ) | | (1 | ) |
| Unamortized debt issuance costs | | | | | | | (7 | ) | | (5 | ) |
| Long-term debt due within one year | | | | | | | (18 | ) | | (281 | ) |
| Long-term debt | | | | | | | $ | 1,170 |
|
| $ | 840 |
|
__________
| |
(a) | Substantially all of ACE's assets are subject to the lien of its respective mortgage indenture. |
| |
(b) | Maturities of ACE's Transition Bonds outstanding at December 31, 2018 are $18 million in 2019, $20 million in 2020 and $21 million in 2021. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
Long-term debt maturities atTax Court’s decision. Exelon Generation, ComEd, PECO, BGE, PHI, Pepco, DPLfiled a petition seeking rehearing of the Seventh Circuit’s decision, but the Seventh Circuit denied that petition in December 2018. In the first quarter of 2019, Exelon elected not to seek a further review by the U.S. Supreme Court. As a result, Exelon's and ACEComEd's unrecognized tax benefits decreased by approximately $33 million and $2 million, respectively, in the periods 2019 through 2023first quarter of 2019.
Recognition of unrecognized tax benefits
The following table presents Exelon's, Generation's, and thereafterPHI's unrecognized tax benefits that, if recognized, would decrease the effective tax rate. ComEd's, PECO's, BGE's, Pepco's, DPL's, and ACE's amounts are as follows:not material.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2019 | $ | 1,349 |
| | $ | 906 |
| | $ | 300 |
| | $ | — |
| | $ | — |
| | $ | 125 |
| | $ | 15 |
| | $ | 91 |
| | $ | 18 |
|
| 2020 | 3,528 |
| | 2,108 |
| | 500 |
| | — |
| | — |
| | 20 |
| | — |
| | — |
| | 20 |
|
| 2021 | 1,511 |
| | 1 |
| | 350 |
| | 300 |
| | 300 |
| | 261 |
| | 1 |
| | — |
| | 260 |
|
| 2022 | 3,084 |
| | 1,024 |
| | — |
| | 350 |
| | 250 |
| | 310 |
| | 310 |
| | — |
| | — |
|
| 2023 | 850 |
| | — |
| | — |
| | 50 |
| | 300 |
| | 500 |
| | — |
| | 500 |
| | — |
|
| Thereafter | 24,979 |
| (a) | 4,720 |
| | 7,243 |
| (b) | 2,609 |
| (c) | 2,050 |
| | 4,420 |
| | 2,425 |
| | 913 |
| | 898 |
|
| Total | $ | 35,301 |
| | $ | 8,759 |
| | $ | 8,393 |
| | $ | 3,309 |
|
| $ | 2,900 |
|
| $ | 5,636 |
|
| $ | 2,751 |
|
| $ | 1,504 |
|
| $ | 1,196 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | PHI(a) | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| December 31, 2020 | $ | 73 | | | $ | 39 | | | $ | 33 | | | | | | | |
| December 31, 2019 | 462 | | | 429 | | | 32 | | | | | | | |
| December 31, 2018 | 463 | | | 408 | | | 31 | | | | | | | |
__________
| |
(a) | Includes $390 million due to ComEd and PECO financing trusts. |
| |
(b) | Includes $206 million due to ComEd financing trust. |
| |
(c) | Includes $184 million due to PECO financing trusts. |
Junior Subordinated Notes
In June 2014, Exelon issued $1.15 billion(a)PHI has $21 million of junior subordinated notesunrecognized state tax benefits that, if recognized, $14 million would be in the form of 23a net operating loss carryforward, which is expected to require a full valuation allowance based on present circumstances.
ACE has $14 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earningsunrecognized tax benefits as of December 31, 2017. See Note 20 — Earnings Per Share for additional information2020, 2019 and 2018 that, if recognized, may be included in future base rates and that portion would have no impact on the issuanceeffective tax rate. Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI's, Pepco's, and DPL's amounts are not material.
Reasonably possible the total amount of common stock.unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.9 billion of generating assets have been pledged as collateral at December 31, 2018. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.
Denver Airport. In June 2011, Generation entered into a 20-year, $7 million solar loan agreement to finance a solar construction project in Denver, Colorado. The agreement is scheduled to mature on June 30, 2031. The agreement bears interest at a fixed rate of 5.50% annually with interest payable annually. As of December 31, 2018, $62020, ACE has approximately $14 million was outstanding.
CEU Upstream. In July 2011, CEU Holdings, LLC, a wholly owned subsidiary of Generation, entered into a 5-year reserveunrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date based lending agreement (RBL) associated with certain Upstream oilon the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and gas properties. The lenders do notthat portion would have recourse against Exelon or Generation in the event of default pursuantno impact to the RBL. Borrowings under this arrangementeffective tax rate.
Total amounts of interest and penalties recognized
The following table represents the net interest and penalties receivable (payable) related to tax positions reflected in Exelon's Consolidated Balance Sheets. Generation's and the Utility Registrants' amounts are secured by the assets and equitynot material.
| | | | | |
| Net interest and penalties receivable as of | Exelon |
| December 31, 2020 | $ | 314 | |
| December 31, 2019 | 318 | |
In December 2016, substantially all of the Upstream natural gas and oil exploration and production assets were sold for $37 million. The proceeds were used to reduce the debt balance by $31 million. The remaining proceeds
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
of $6 million were being heldThe Registrants did not record material interest and penalty expense related to tax positions reflected in escrow. In addition, during 2016, $15 million of the debt was repaid using CEU Holding’s cash, resulting in an outstanding debt balance of $22 million at December 31, 2016. During 2017, additional assets were sold for $1 million and the remaining $6 million in escrow was released and applied to the debt balance resulting in an outstanding amount of $15 million at December 31, 2017. Upon final resolution, CEU Holdings will be released of its obligations regardless of the amount of asset sale proceeds received. The ultimate resolution of this matter has no direct effect on any Exelon or Generation credit facilities or other debt of an Exelon entity. At December 31, 2018, the outstanding debt balance of $15 million was classified within Long term debt due within one year in Exelon’s and Generation’stheir Consolidated Balance Sheets. See Note 5 — Mergers, AcquisitionsInterest expense and Dispositionspenalty expense are recorded in Interest expense, net and Note 7 — Impairment of Long-Lived AssetsOther, net, respectively, in Other income and Intangibles for additional information.
Holyoke Solar Cooperative. In October 2011, Generation entered into a 20-year, $11 million solar loan agreement related to a solar construction project in Holyoke, Massachusetts. The agreement is scheduled to mature on December 2031. The agreement bears interest at a fixed rate of 5.25% annually with interest payable monthly. As of December 31, 2018, $8 million was outstanding.
Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance will bear interest at an average blended interest rate of 2.82%. As of December 31, 2018, $508 million was outstanding. In addition, Generation has issued letters of credit to support its equity investmentdeductions in the project. As of December 31, 2018, Generation had $38 million in letters of credit outstanding related to the project. In 2017, Generation’s interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.
Continental Wind. In September 2013, Continental Wind, LLC (Continental Wind), an indirect subsidiary of Exelon and Generation, completed the issuance and sale of $613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667MW. The net proceeds were distributed to Generation for its general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2018, $479 million was outstanding.
In addition, Continental Wind entered into a $131 million letter of credit facility and $10 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2018, the Continental Wind letter of credit facility had $114 million in letters of credit outstanding related to the project.
In 2017, Generation’s interests in Continental Wind were contributed to EGRP. Refer to Note 2 - Variable Interest Entities for additional information on EGRP.
ExGen Texas Power. In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan. The net proceeds were distributed to Generation for general business purposes. The loan was scheduled to mature on September 18, 2021. In addition to the financing, EGTP entered into various interest rate swaps with an initial notional amount of approximately $505 million at an interest rate of 2.34% to hedge a portion of the interest rate exposure in connection with this financing, as required by the debt covenants.
On May 2, 2017, as a result of the negative impacts of certain market conditions and the seasonality of its cash flows, EGTP entered into a consent agreement with its lenders, which permitted EGTP to draw on its revolving credit facility and initiate an orderly sales process of its assets. On November 7, 2017, the debtors filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware. As a result, Exelon and Generation deconsolidated the nonrecourse senior secured term loan, the revolving credit facility, and the interest rate swaps from their consolidated financial statements as of December 31, 2017. Due to their nonrecourse nature, these borrowings are secured solely by the assets of EGTP and its subsidiaries.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders. See Note 5 — Mergers, Acquisitions and Dispositions for additional information on EGTP.
Renewable Power Generation. In March 2016, RPG, an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for paydown of long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature on March 31, 2035. The term loan bears interest at a fixed rate of 4.11% payable semi-annually. As of December 31, 2018, $115 million was outstanding.
In 2017, Generation’s interests in Renewable Power Generation were contributed to EGRP. Refer to Note 2 - Variable interest Entities for additional information on EGRP.
SolGen. In September 2016, SolGen, LLC (SolGen), an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for general business purposes. The loan is scheduled to mature on September 30, 2036. The term loan bears interest at a fixed rate of 3.93% payable semi-annually. As of December 31, 2018, $137 million was outstanding. In 2017, Generation’s interests in SolGen were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.
ExGen Renewables IV. In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this financing. The net proceeds of $785 million, after the initial funding of $50 million for debt service and liquidity reserves as well as deductions for original discount and estimated costs, fees and expenses incurred in connection with the execution and delivery of the credit facility agreement, were distributed to Generation for general corporate purposes. The $50 million of debt service and liquidity reserves was treated as restricted cash in Exelon’s and Generation’s Consolidated Balance Sheets andRegistrants' Consolidated Statements of Cash Flows. The loan is scheduledOperations and Comprehensive Income.
Description of tax years open to mature on November 28, 2024. The term loan bears interest at a variable rate equalassessment by major jurisdiction
| | | | | | | | | | | |
| Major Jurisdiction | Open Years | | Registrants Impacted |
Federal consolidated income tax returns(a) | 2010-2019 | | All Registrants |
| Delaware separate corporate income tax returns | Same as federal | | DPL |
| District of Columbia combined corporate income tax returns | 2017-2019 | | Exelon, PHI, Pepco |
| Illinois unitary corporate income tax returns | 2012-2019 | | Exelon, Generation, ComEd |
| Maryland separate company corporate net income tax returns | Same as federal | | BGE, Pepco, DPL |
| New Jersey separate corporate income tax returns | 2013-2019 | | Exelon, Generation |
| New Jersey separate corporate income tax returns | 2014-2019 | | ACE |
| New York combined corporate income tax returns | 2010-March 2012 | | Exelon, Generation |
| New York combined corporate income tax returns | 2011-2019 | | Exelon, Generation |
| Pennsylvania separate corporate income tax returns | 2011-2019 | | Exelon, Generation |
| Pennsylvania separate corporate income tax returns | 2017-2019 | | PECO |
__________
(a)Certain registrants are only open to LIBOR + 3%, subject to a 1% LIBOR floor with interest payable quarterly. As of December 31, 2018, $834 million was outstanding. In addition toassessment for tax years since joining the financing, EGR IV entered into interest rate swaps with an initial notional amount of $636 million at an interest rate of 2.32% to manage a portion of the interest rate exposureExelon federal consolidated group; BGE beginning in connection with the financing. See Note 2 - Variable interest Entities for additional information on EGRP.2012 and PHI, Pepco, DPL, and ACE beginning in 2016.
14.Long-Term Marginal State Income TaxesTax Rate (All Registrants)
Corporate Tax Reform (All Registrants)
On December 22, 2017, President Trump signed the TCJA into law. The TCJA makes many significant changes to the Internal Revenue Code, including, but not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21%; (2) creating a 30% limitation on deductible interest expense (not applicable to regulated utilities); (3) allowing 100% expensing for the cost of qualified property (not applicable to regulated utilities); (4) eliminating the domestic production activities deduction; (5) eliminating the corporate alternative minimum taxQuarterly, Exelon reviews and changing how existing alternative minimum tax credits can be realized; and (6) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning after December 31, 2017. The most significant change that impacts the Registrants is the reduction of the corporate federalupdates its marginal state income tax rate from 35% to 21% beginning January 1, 2018.
Pursuant to the enactment of the TCJA, therates for changes in state apportionment. The Registrants remeasuredremeasure their existing deferred income tax balances as of December 31, 2017 to reflect the decreasechanges in the corporate income tax rate from 35% to 21%,marginal rates, which resultedresults in either an increase or a material decrease to their net deferred income tax liability balances as shown in the table below. Generation recorded a corresponding net decrease to income tax expense, while thebalances. Utility Registrants recordedrecord corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts. The impacts to the Utility Registrants for the years ended December 31, 2020, 2019, and 2018 were not material.
| | | | | | | | | | | | | | | |
| December 31, 2020 | Exelon | | Generation | | | | |
| Increase (decrease) to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes | $ | 66 | | | $ | (26) | | | | | |
| | | | | | | |
| December 31, 2019 | | | | | | | |
| Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes | $ | 23 | | | $ | 9 | | | | | |
| | | | | | | |
| December 31, 2018 | | | | | | | |
| Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes | $ | (50) | | | $ | (53) | | | | | |
| | | | | | | |
Allocation of Tax Benefits (All Registrants)
Generation and the Utility Registrants are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net federal and timing of potential settlementsstate benefits attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the established net regulatory liabilities are determined byparty receiving the Utility Registrants’ respective rate regulators, subject to certain IRS “normalization” rules. See Note 4 — Regulatory Matters for additional information regarding settlements for passing backbenefit.
The following table presents the allocation of TCJA income tax savings benefits to customers.from Exelon under the Tax Sharing Agreement.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
The Registrants assessed | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
December 31, 2020(a) | $ | 64 | | | $ | 14 | | | $ | 17 | | | $ | 0 | | | $ | 17 | | | $ | 8 | | | $ | 6 | | | $ | 1 | |
December 31, 2019(b) | 41 | | | 0 | | | 14 | | | 3 | | | 7 | | | 6 | | | 1 | | | 0 | |
December 31, 2018(c) | 155 | | | 1 | | | 48 | | | 26 | | | 2 | | | 0 | | | 0 | | | 0 | |
__________
(a)BGE did not record an allocation of federal tax benefits from Exelon under the applicable provisionsTax Sharing Agreement as a result of a tax net operating loss.
(b)ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
(c)Pepco, DPL, and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
Research and Development Activities
In the fourth quarter of 2019, Exelon and Generation recognized additional tax benefits related to certain research and development activities that qualify for federal and state tax incentives for the 2010 through 2018 tax years, which resulted in an increase to Exelon’s and Generation’s net income of $108 million and $75 million, respectively, for the TCJA and recorded the associated impacts as ofyear ended December 31, 2017.2019, reflecting a decrease to Exelon’s and Generation’s Income tax expense of $97 million and $66 million, respectively.
15. Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and OPEB plans for essentially all current employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018 for most newly-hired Generation and BSC non-represented, non-craft, employees and January 1, 2021 for most newly-hired utility management employees, these newly-hired employees are not eligible for pension benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits. Effective January 1, 2021, most non-represented, non-craft, employees who are under the age of 40 are not eligible for retiree health care benefits.
Effective January 1, 2019, Exelon merged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The Registrants recorded provisional income tax amounts asmerging of December 31, 2017, as allowed under SAB 118 issued by the SEC in December 2017, for changes pursuantplans did not change the benefits offered to the TCJAplan participants and, thus, had no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to depreciation because the impacts could not be finalized upon issuanceCBPP and ECRP are amortized over participants’ average remaining service period of the Registrants’ financial statements, but for which reasonable estimates could be determined.
On August 3, 2018, the U.S. Department of Treasury, in conjunction with the IRS, released proposed regulations clarifying the immediate expensing provisions enacted by the TCJA, specifically that regulated utility property acquired after September 27, 2017, and placed in service by December 31, 2017, qualifies for 100% expensing. Until the proposed regulations are finalized, taxpayers may rely on the proposed regulations for tax years ending after September 28, 2017. The Registrants recorded the impact of these proposed regulations and the adjustment was immaterial.
While the Registrants have recorded the impacts of the TCJA based on their interpretation of the provisions as enacted, it is expected the U.S. Department of Treasury and the IRS will issue additional interpretative guidance in the future that could result in changes to previously finalized provisions. At this time, many of the states in which Exelon does business have issued guidance regarding TCJA and the impact was not material.
The one-time impacts recorded by the Registrants to remeasure their deferred income tax balances at the 21% corporate federal income tax rate as of December 31, 2017 are presented below:merged ECRP rather than each individual plan.
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon(b) | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Net Decrease to Deferred Income Tax Liability Balances
| $8,624 | | $1,895 | | $2,819 | | $1,407 | | $1,120 | | $1,944 | | $968 | | $540 | | $456 |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO(c) | | BGE | | PHI | | Pepco | | DPL | | ACE |
Net Regulatory Liability Recorded(a) | $7,315 | | N/A | | $2,818 | | $1,394 | | $1,124 | | $1,979 | | $976 | | $545 | | $458 |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon(b) | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Net Deferred Income Tax Benefit/(Expense) Recorded | $1,309 | | $1,895 | | $1 | | $13 | | $(4) | | $(35) | | $(8) | | $(5) | | $(2) |
__________
| |
(a) | Reflects the net regulatory liabilities recorded on a pre-tax basis before taking into consideration the income tax benefits associated with the ultimate settlement with customers. |
| |
(b) | Amounts do not sum across due to deferred tax adjustments recorded at the Exelon Corporation parent company, primarily related to certain employee compensation plans. |
| |
(c) | Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remained in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. |
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
The table below shows the pension and OPEB plans in which employees of each operating company participated at December 31, 2020:
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | Successor | | | | | | |
| | Exelon | | ComEd | | PECO(a) | | BGE | | PHI | | PEPCO | | DPL | | ACE |
| Subject to IRS Normalization Rules | $3,040 | | $1,400 | | $533 | | $459 | | $648 | | $299 | | $195 | | $153 |
| Subject to Rate Regulator Determination | 1,694 | | 573 | | 43 | | 324 | | 754 | | 391 | | 194 | | 170 |
|
| Net Regulatory Liabilities | $4,734 | | $1,973 | | $576 | | $783 | | $1,402 | | $690 | | $389 | | $ | 323 |
|
_________ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(a) | Given the regulatory treatment | | | Operating Company(e) |
Name of income tax benefits related to electricPlan: | | | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Qualified Pension Plans: | | | | | | | | | | | | | | | | | | |
Exelon Corporation Retirement Program(a) | | | | X | | X | | X | | X | | X | | X | | X | | X |
Exelon Corporation Pension Plan for Bargaining Unit Employees(a) | | | | X | | X | | | | | | | | | | | | |
Exelon New England Union Employees Pension Plan(a) | | | | X | | | | | | | | | | | | | | |
Exelon Employee Pension Plan for Clinton, TMI, and gas distribution repairs, PECO was in an overall net regulatory asset position asOyster Creek(a) | | | | X | | X | | X | | X | | X | | | | | | X |
Pension Plan of December 31, 2017 after recording the impacts related to the TCJA. As a result, the amountConstellation Energy Group, Inc.(b) | | | | X | | X | | X | | X | | X | | X | | X | | |
Pension Plan of customer benefits resulting from the TCJA subject to the discretion of PECO's rate regulators are lower relative to the other Utility Registrants.Constellation Energy Nuclear Group, LLC(c) | | | | X | | X | | | | X | | X | | X | | | | |
Nine Mile Point Pension Plan(c) | | | | X | | | | | | | | | | | | | | |
Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B(b) | | | | X | | | | | | | | | | | | | | |
Pepco Holdings LLC Retirement Plan(d) | | | | X | | X | | X | | X | | X | | X | | X | | X |
| Non-Qualified Pension Plans: | | | | | | | | | | | | | | | | | | |
Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan(a) | | | | X | | X | | X | | | | X | | | | | | |
Exelon Corporation Supplemental Management Retirement Plan(a) | | | | X | | X | | X | | X | | X | | X | | | | X |
Constellation Energy Group, Inc. Senior Executive Supplemental Plan(b) | | | | X | | | | | | X | | X | | | | | | |
Constellation Energy Group, Inc. Supplemental Pension Plan(b) | | | | X | | | | | | X | | X | | | | | | |
Constellation Energy Group, Inc. Benefits Restoration Plan(b) | | | | X | | X | | | | X | | X | | | | | | |
Constellation Energy Nuclear Plan, LLC Executive Retirement Plan(c) | | | | X | | | | | | | | X | | | | | | |
Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan(c) | | | | X | | | | | | | | X | | | | | | |
Baltimore Gas & Electric Company Executive Benefit Plan(b) | | | | X | | | | | | X | | | | | | | | |
Baltimore Gas & Electric Company Manager Benefit Plan(b) | | | | X | | X | | | | X | | | | | | | | |
Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan(d) | | | | X | | | | | | | | X | | X | | X | | X |
Conectiv Supplemental Executive Retirement Plan(d) | | | | X | | | | | | | | X | | | | X | | X |
Pepco Holdings LLC Combined Executive Retirement Plan(d) | | | | | | | | | | | | X | | X | | | | |
Atlantic City Electric Director Retirement Plan(d) | | | | | | | | | | | | | | | | | | X |
The net regulatory liability amounts
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Operating Company(e) |
| Name of Plan: | | | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| OPEB Plans: | | | | | | | | | | | | | | | | | | |
PECO Energy Company Retiree Medical Plan(a) | | | | X | | X | | X | | X | | X | | X | | X | | X |
Exelon Corporation Health Care Program(a) | | | | X | | X | | X | | X | | X | | X | | | | X |
Exelon Corporation Employees’ Life Insurance Plan(a) | | | | X | | X | | X | | X | | | | | | | | |
Exelon Corporation Health Reimbursement Arrangement Plan(a) | | | | X | | X | | X | | X | | | | | | | | |
Constellation Energy Group, Inc. Retiree Medical Plan(b) | | | | X | | X | | X | | X | | X | | X | | | | |
Constellation Energy Group, Inc. Retiree Dental Plan(b) | | | | X | | | | | | X | | | | | | | | |
Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan(b) | | | | X | | X | | X | | X | | X | | X | | | | |
Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan(b) | | | | X | | | | | | X | | | | | | | | |
Exelon New England Union Post-Employment Medical Savings Account Plan(a) | | | | X | | | | | | | | | | | | | | |
Retiree Medical Plan of Constellation Energy Nuclear Group, LLC(c) | | | | X | | X | | | | X | | | | X | | | | |
Retiree Dental Plan of Constellation Energy Nuclear Group, LLC(c) | | | | X | | X | | | | X | | | | X | | | | |
Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees(c) | | | | X | | | | | | | | | | | | | | |
Pepco Holdings LLC Welfare Plan for Retirees(d) | | | | X | | X | | X | | X | | X | | X | | X | | X |
__________
(a)These plans are collectively referred to as the legacy Exelon plans.
(b)These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans.
(c)These plans are collectively referred to as the legacy CENG plans.
(d)These plans are collectively referred to as the legacy PHI plans.
(e)Employees generally remain in their legacy benefit plans when transferring between operating companies.
Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Exelon has elected that the trusts underlying these plans be treated as qualified trusts under the IRC. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations.
Benefit Obligations, Plan Assets, and Funded Status
During the IRS normalization rules generally relatefirst quarter of 2020, Exelon received an updated valuation of its pension and OPEB to property,reflect actual census data as of January 1, 2020. This valuation resulted in an increase to the pension and OPEB obligations of $8 million and $31 million, respectively. Additionally, accumulated other comprehensive loss increased by $7 million (after-tax) and regulatory assets and liabilities increased by $19 million and decreased by $10 million, respectively.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
The following tables provide a rollforward of the changes in the benefit obligations and plan assets of Exelon for the most recent two years for all plans combined:
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2020 | | 2019 |
| Change in benefit obligation: | | | | | | | |
| Net benefit obligation at beginning of year | $ | 22,868 | | | $ | 20,692 | | | $ | 4,658 | | | $ | 4,369 | |
| Service cost | 387 | | | 357 | | | 90 | | | 93 | |
| Interest cost | 757 | | | 883 | | | 154 | | | 188 | |
| Plan participants’ contributions | 0 | | | 0 | | | 49 | | | 44 | |
Actuarial loss(a) | 2,217 | | | 2,322 | | | 49 | | | 250 | |
| Plan amendments | 0 | | | 68 | | | (111) | | | 0 | |
| | | | | | | |
| Curtailments | 0 | | | (3) | | | 0 | | | 0 | |
| Settlements | (45) | | | (35) | | | (5) | | | (4) | |
| Contractual termination benefits | 0 | | | 1 | | | 0 | | | 0 | |
| Gross benefits paid | (1,290) | | | (1,417) | | | (280) | | | (282) | |
| Net benefit obligation at end of year | $ | 24,894 | | | $ | 22,868 | | | $ | 4,604 | | | $ | 4,658 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2020 | | 2019 |
| Change in plan assets: | | | | | | | |
| Fair value of net plan assets at beginning of year | $ | 18,590 | | | $ | 16,678 | | | $ | 2,541 | | | $ | 2,408 | |
| Actual return on plan assets | 2,547 | | | 3,008 | | | 190 | | | 324 | |
| Employer contributions | 542 | | | 356 | | | 59 | | | 51 | |
| Plan participants’ contributions | 0 | | | 0 | | | 49 | | | 44 | |
| Gross benefits paid | (1,290) | | | (1,417) | | | (280) | | | (282) | |
| | | | | | | |
| Settlements | (45) | | | (35) | | | (5) | | | (4) | |
| Fair value of net plan assets at end of year | $ | 20,344 | | | $ | 18,590 | | | $ | 2,554 | | | $ | 2,541 | |
__________
(a)The pension and OPEB actuarial losses in 2020 and 2019 primarily reflect a decrease in the discount rate. OPEB losses in 2020 were offset by gains related to plan changes.
Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2020 | | 2019 |
| Other current liabilities | $ | 47 | | | $ | 31 | | | $ | 42 | | | $ | 41 | |
| Pension obligations | 4,503 | | | 4,247 | | | 0 | | | 0 | |
| Non-pension postretirement benefit obligations | 0 | | | 0 | | | 2,008 | | | 2,076 | |
| Unfunded status (net benefit obligation less plan assets) | $ | 4,550 | | | $ | 4,278 | | | $ | 2,050 | | | $ | 2,117 | |
The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. Information for pension and OPEB plans with projected benefit obligations (PBO) and accumulated postretirement benefit obligation (APBO), respectively, in excess of plan assets has been disclosed in the Obligations and Plan Assets table above as all pension and OPEB plans are underfunded.
| | | | | | | | | | | | | |
| ABO in excess of plan assets | Exelon | | |
| 2020 | | 2019 | | |
| | | | | |
| ABO | $ | 23,514 | | | $ | 21,727 | | | |
| Fair value of net plan assets | 20,344 | | | 18,590 | | | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Components of Net Periodic Benefit Costs
The majority of the 2020 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.34%. The majority of the 2020 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.69% for funded plans and a discount rate of 3.31%.
A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2020, 2019, and 2018.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 |
| Components of net periodic benefit cost: | | | | | | | | | | | |
| Service cost | $ | 387 | | | $ | 357 | | | $ | 405 | | | $ | 90 | | | $ | 93 | | | $ | 112 | |
| Interest cost | 757 | | | 883 | | | 802 | | | 154 | | | 188 | | | 175 | |
| Expected return on assets | (1,270) | | | (1,225) | | | (1,252) | | | (163) | | | (153) | | | (173) | |
| Amortization of: | | | | | | | | | | | |
| | | | | | | | | | | |
| Prior service cost (credit) | 4 | | | 0 | | | 2 | | | (124) | | | (179) | | | (186) | |
| Actuarial loss | 512 | | | 414 | | | 629 | | | 49 | | | 45 | | | 66 | |
| Curtailment benefits | 0 | | | 0 | | | 0 | | | (1) | | | 0 | | | 0 | |
| Settlement and other charges | 14 | | | 17 | | | 3 | | | 1 | | | 1 | | | 1 | |
| Contractual termination benefits | 0 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Net periodic benefit cost | $ | 404 | | | $ | 447 | | | $ | 589 | | | $ | 6 | | | $ | (5) | | | $ | (5) | |
Cost Allocation to Exelon Subsidiaries
All Registrants account for their participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocates costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan.
The amounts below represent the Registrants' allocated pension and OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, with remaining useful lives ranging from 30 to 40 years acrossnet while the non-service cost components are included in Other, net and Regulatory assets. For Generation and the Utility Registrants.Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2020 | $ | 411 | | | $ | 115 | | | $ | 114 | | | $ | 5 | | | $ | 64 | | | $ | 70 | | | $ | 15 | | | $ | 7 | | | $ | 14 | |
| 2019 | 442 | | | 135 | | | 96 | | | 12 | | | 61 | | | 95 | | | 25 | | | 15 | | | 16 | |
| 2018 | 583 | | | 204 | | | 177 | | | 18 | | | 60 | | | 67 | | | 15 | | | 6 | | | 12 | |
Components of AOCI and Regulatory Assets
Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its balance sheet, with offsetting entries to AOCI and regulatory assets (liabilities). A portion of current year actuarial (gains) losses and prior service costs (credits) is capitalized within Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets (liabilities) for Exelon for the years ended December 31, 2020, 2019, and 2018 for all plans combined.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 |
| Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities): | | | | | | | | | | | |
| Current year actuarial loss (gain) | $ | 941 | | | $ | 538 | | | $ | 635 | | | $ | 22 | | | $ | 80 | | | $ | (232) | |
| Amortization of actuarial loss | (512) | | | (414) | | | (629) | | | (49) | | | (45) | | | (66) | |
| Current year prior service cost (credit) | 0 | | | 68 | | | (4) | | | (111) | | | 0 | | | 0 | |
| Amortization of prior service (cost) credit | (4) | | | 0 | | | (2) | | | 124 | | | 179 | | | 186 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Curtailments | 0 | | | (3) | | | 0 | | | 1 | | | 0 | | | 0 | |
| Settlements | (14) | | | (17) | | | (3) | | | (1) | | | (1) | | | 0 | |
| | | | | | | | | | | |
| Total recognized in AOCI and regulatory assets (liabilities) | $ | 411 | | | $ | 172 | | | $ | (3) | | | $ | (14) | | | $ | 213 | | | $ | (112) | |
| | | | | | | | | | | |
| Total recognized in AOCI | $ | 271 | | | $ | 169 | | | $ | 3 | | | $ | 6 | | | $ | 107 | | | $ | (55) | |
| Total recognized in regulatory assets (liabilities) | $ | 140 | | | $ | 3 | | | $ | (6) | | | $ | (20) | | | $ | 106 | | | $ | (57) | |
The following table provides the components of gross accumulated other comprehensive loss and regulatory assets (liabilities) for Exelon that have not been recognized as components of periodic benefit cost at December 31, 2020 and 2019, respectively, for all plans combined:
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | |
| | Pension Benefits | | | | OPEB | | |
| 2020 | | 2019 | | | | 2020 | | 2019 | | |
| Prior service cost (credit) | $ | 35 | | | $ | 39 | | | | | $ | (145) | | | $ | (158) | | | |
| Actuarial loss | 8,077 | | | 7,662 | | | | | 538 | | | 565 | | | |
| Total | $ | 8,112 | | | $ | 7,701 | | | | | $ | 393 | | | $ | 407 | | | |
| | | | | | | | | | | |
| Total included in AOCI | $ | 4,339 | | | $ | 4,068 | | | | | $ | 183 | | | $ | 177 | | | |
| Total included in regulatory assets (liabilities) | $ | 3,773 | | | $ | 3,633 | | | | | $ | 210 | | | $ | 230 | | | |
Average Remaining Service Period
For pension benefits, Exelon amortizes its unrecognized prior service costs (credits) and certain actuarial (gains) losses, as applicable, based on participants’ average remaining service periods.
For OPEB, Exelon amortizes its unrecognized prior service costs (credits) over participants’ average remaining service period to benefit eligibility age and amortizes certain actuarial (gains) losses over participants’ average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB were as follows:
| | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| Pension plans | | 12.3 | | | 11.7 | | | 12.0 | |
| OPEB plans: | | | | | | |
| Benefit Eligibility Age | | 9.0 | | | 8.7 | | | 8.8 | |
| Expected Retirement | | 10.2 | | | 9.3 | | | 9.5 | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Assumptions
The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and OPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, Exelon considers historical information as well as future expectations.
Expected Rate of Return. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.
Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. For the otheryear endedDecember 31, 2020, Exelon’s mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2020 improvement scale adjusted to use Proxy SSA ultimate improvement rates. For the year ended December 31, 2019, Exelon's mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2019 improvement scale adjusted to a 0.75% long-term rate reached in 2035.
For Exelon, the following assumptions were used to determine the benefit obligations for the plans at December 31, 2020 and 2019. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB | |
| 2020 | | 2019 | | 2020 | | 2019 | |
| Discount rate | 2.58 | % | (a) | 3.34 | % | (a) | 2.51 | % | (a) | 3.31 | % | (a) |
| Investment crediting rate | 3.72 | % | (b) | 3.82 | % | (b) | N/A | | N/A | |
| Rate of compensation increase | 3.75 | % | | | (c) | 3.75 | % | | | (c) |
| Mortality table | Pri-2012 table with MP- 2020 improvement scale (adjusted) | | Pri-2012 table with MP- 2019 improvement scale (adjusted) | | Pri-2012 table with MP- 2020 improvement scale (adjusted) | | Pri-2012 table with MP- 2019 improvement scale (adjusted) | |
| Health care cost trend on covered charges | N/A | | N/A | | Initial and ultimate rate of 5.00% | | 5.00% with ultimate trend of 5.00% in 2017 | |
__________
(a)The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and OPEB obligations. Certain benefit plans used individual rates, which range from 2.11% - 2.73% and 2.45% - 2.63% for pension and OPEB plans, respectively, as of December 31, 2020 and 3.02% - 3.44% and 3.27% - 3.40% for pension and OPEB plans, respectively, as of December 31, 2019.
(b)The investment crediting rate above represents a weighted average rate.
(c)3.25% through 2019 and 3.75% thereafter.
The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2020, 2019 and 2018:
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB | |
| 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 | |
| Discount rate | 3.34 | % | (a) | 4.31 | % | (a) | 3.62 | % | (a) | 3.31 | % | (a) | 4.30 | % | (a) | 3.61 | % | (a) |
| Investment crediting rate | 3.82 | % | (b) | 4.46 | % | (b) | 4.00 | % | (b) | N/A | | N/A | | N/A | |
| Expected return on plan assets | 7.00 | % | (c) | 7.00 | % | (c) | 7.00 | % | (c) | 6.69 | % | (c) | 6.67 | % | (c) | 6.60 | % | (c) |
| Rate of compensation increase | | (d) | | (d) | | (d) | | (d) | | (d) | | (d) |
| Mortality table | Pri-2012 table with MP- 2019 improvement scale (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | Pri-2012 table with MP- 2019 improvement scale (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | |
| Health care cost trend on covered charges | N/A | | N/A | | N/A | | Initial and ultimate rate of 5.00% | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.00% with ultimate trend of 5.00% in 2017 | |
__________
(a)The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and OPEB costs. Certain benefit plans used individual rates, which range from 3.02%-3.44% and 3.27%-3.40% for pension and OPEB plans, respectively, for the year ended December 31, 2020; 4.13%-4.36% and 4.27%-4.38% for pension and OPEB plans; respectively, for the year ended December 31, 2019; and 3.49%-3.65% and 3.57%-3.68% for pension and OPEB plans, respectively, for the year ended December 31, 2018.
(b)The investment crediting rate above represents a weighted average rate.
(c)Not applicable to pension and OPEB plans that do not have plan assets.
(d)3.25% through 2019 and 3.75% thereafter.
Contributions
Exelon allocates contributions related to its legacy Exelon pension and OPEB plans to its subsidiaries based on accounting cost. For legacy CEG, CENG, FitzPatrick, and PHI plans, pension and OPEB contributions are allocated to the subsidiaries based on employee participation (both active and retired). The following tables provide contributions to the pension and OPEB plans:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB | |
| | 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 | |
| Exelon | $ | 542 | | | $ | 356 | | | $ | 337 | | | $ | 59 | | | $ | 51 | | | $ | 46 | | |
| Generation | 236 | | | 160 | | | 128 | | | 19 | | | 15 | | | 11 | | |
| ComEd | 143 | | | 72 | | | 38 | | | 5 | | | 5 | | | 4 | | |
| PECO | 18 | | | 27 | | | 28 | | | 0 | | | 1 | | | 0 | | |
| BGE | 56 | | | 34 | | | 40 | | | 22 | | | 14 | | | 14 | | |
| PHI | 30 | | | 10 | | | 62 | | | 9 | | | 15 | | | 12 | | |
| Pepco | 2 | | | 2 | | | 6 | | | 9 | | | 12 | | | 11 | | |
| DPL | 0 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | |
| ACE | 2 | | | 0 | | | 6 | | | 0 | | | 1 | | | 0 | | |
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change,
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Exelon’s estimated annual qualified pension contributions will be approximately $500 million in 2021. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.
While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts rate regulators could requirebelow include benefit payments related to unfunded plans.
The following table provides all Registrants' planned contributions to the passing backqualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2021:
| | | | | | | | | | | | | | | | | |
| Qualified Pension Plans | | Non-Qualified Pension Plans | | OPEB |
| Exelon | $ | 505 | | | $ | 51 | | | $ | 75 | |
| Generation | 196 | | | 27 | | | 24 | |
| ComEd | 170 | | | 2 | | | 23 | |
| PECO | 14 | | | 1 | | | 0 | |
| BGE | 57 | | | 1 | | | 16 | |
| PHI | 29 | | | 9 | | | 7 | |
| Pepco | 1 | | | 2 | | | 6 | |
| DPL | 0 | | | 1 | | | 0 | |
| ACE | 3 | | | 0 | | | 0 | |
Estimated Future Benefit Payments
Estimated future benefit payments to participants in all of amountsthe pension plans and postretirement benefit plans at December 31, 2020 were:
| | | | | | | | | | | |
| Pension
Benefits | | OPEB |
| 2021 | $ | 1,279 | | | $ | 257 | |
| 2022 | 1,280 | | | 259 | |
| 2023 | 1,315 | | | 261 | |
| 2024 | 1,325 | | | 262 | |
| 2025 | 1,338 | | | 265 | |
| 2026 through 2030 | 6,759 | | | 1,320 | |
| Total estimated future benefit payments through 2030 | $ | 13,296 | | | $ | 2,624 | |
Plan Assets
Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to customers over shorter time frames. ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.
Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon’s OPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.
Actual asset returns have an impact on the costs reported for the Exelon-sponsored pension and OPEB plans. The actual asset returns across Exelon’s pension and OPEB plans for the year ended December 31, 2020 were 14.45% and 9.14%, respectively, compared to an expected long-term return assumption of 7.00% and 6.69%,
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
respectively. Exelon used an EROA of 7.00% and 6.46% to estimate its 2021 pension and OPEB costs, respectively.
Exelon’s pension and OPEB plan target asset allocations at December 31, 2020 and 2019 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Asset Category | Pension Benefits | | OPEB | | Pension Benefits | | OPEB |
| Equity securities | 34 | % | | 45 | % | | 33 | % | | 46 | % |
| Fixed income securities | 43 | % | | 39 | % | | 44 | % | | 32 | % |
Alternative investments(a) | 23 | % | | 16 | % | | 23 | % | | 22 | % |
| Total | 100 | % | | 100 | % | | 100 | % | | 100 | % |
__________
(a)Alternative investments include private equity, hedge funds, real estate, and private credit.
Concentrations of Credit Risk. Exelon evaluated its pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2020. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2020, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and OPEB plan assets.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Fair Value Measurements
The following tables present pension and OPEB plan assets measured and recorded at fair value in Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Pension plan assets(a) | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | $ | 408 | | | $ | 121 | | | $ | 0 | | | $ | 0 | | | $ | 529 | | | $ | 258 | | | $ | 107 | | | $ | 0 | | | $ | 0 | | | $ | 365 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Equities(b) | 4,255 | | | 0 | | | 2 | | | 2,552 | | | 6,809 | | | 3,616 | | | 1 | | | 5 | | | 2,589 | | | 6,211 | |
| Fixed income: | | | | | | | | | | | | | | | | | | | |
| U.S. Treasury and agencies | 1,137 | | | 367 | | | 0 | | | 0 | | | 1,504 | | | 1,294 | | | 280 | | | 0 | | | 0 | | | 1,574 | |
| State and municipal debt | 0 | | | 85 | | | 0 | | | 0 | | | 85 | | | 0 | | | 56 | | | 0 | | | 0 | | | 56 | |
Corporate debt(c) | 0 | | | 4,873 | | | 573 | | | 0 | | | 5,446 | | | 0 | | | 4,390 | | | 245 | | | 0 | | | 4,635 | |
Other(b) | 0 | | | 239 | | | 21 | | | 537 | | | 797 | | | 0 | | | 305 | | | 0 | | | 851 | | | 1,156 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Fixed income subtotal | 1,137 | | | 5,564 | | | 594 | | | 537 | | | 7,832 | | | 1,294 | | | 5,031 | | | 245 | | | 851 | | | 7,421 | |
| Private equity | 0 | | | 0 | | | 0 | | | 1,632 | | | 1,632 | | | 0 | | | 0 | | | 0 | | | 1,391 | | | 1,391 | |
| Hedge funds | 0 | | | 0 | | | 0 | | | 1,314 | | | 1,314 | | | 0 | | | 0 | | | 0 | | | 1,126 | | | 1,126 | |
| | | | | | | | | | | | | | | | | | | |
| Real estate | 0 | | | 0 | | | 0 | | | 1,080 | | | 1,080 | | | 0 | | | 0 | | | 0 | | | 1,030 | | | 1,030 | |
| Private credit | 0 | | | 0 | | | 234 | | | 1,046 | | | 1,280 | | | 0 | | | 0 | | | 237 | | | 929 | | | 1,166 | |
| Pension plan assets subtotal | 5,800 | | | 5,685 | | | 830 | | | 8,161 | | | 20,476 | | | 5,168 | | | 5,139 | | | 487 | | | 7,916 | | | 18,710 | |
| | | | | | | | | | | | | | | | | | | |
OPEB plan assets(a) | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 50 | | | 52 | | | 0 | | | 0 | | | 102 | | | 39 | | | 49 | | | 0 | | | 0 | | | 88 | |
| Equities | 618 | | | 2 | | | 0 | | | 569 | | | 1,189 | | | 473 | | | 5 | | | 0 | | | 719 | | | 1,197 | |
| Fixed income: | | | | | | | | | | | | | | | | | | | |
| U.S. Treasury and agencies | 16 | | | 66 | | | 0 | | | 0 | | | 82 | | | 17 | | | 64 | | | 0 | | | 0 | | | 81 | |
| State and municipal debt | 0 | | | 89 | | | 0 | | | 0 | | | 89 | | | 0 | | | 107 | | | 0 | | | 0 | | | 107 | |
Corporate debt(c) | 0 | | | 89 | | | 0 | | | 0 | | | 89 | | | 0 | | | 71 | | | 0 | | | 0 | | | 71 | |
| Other | 285 | | | 3 | | | 0 | | | 179 | | | 467 | | | 258 | | | 5 | | | 0 | | | 201 | | | 464 | |
| Fixed income subtotal | 301 | | | 247 | | | 0 | | | 179 | | | 727 | | | 275 | | | 247 | | | 0 | | | 201 | | | 723 | |
| | | | | | | | | | | | | | | | | | | |
| Hedge funds | 0 | | | 0 | | | 0 | | | 308 | | | 308 | | | 0 | | | 0 | | | 0 | | | 293 | | | 293 | |
| Real estate | 0 | | | 0 | | | 0 | | | 111 | | | 111 | | | 0 | | | 0 | | | 0 | | | 109 | | | 109 | |
| Private credit | 0 | | | 0 | | | 0 | | | 117 | | | 117 | | | 0 | | | 0 | | | 0 | | | 131 | | | 131 | |
| OPEB plan assets subtotal | 969 | | | 301 | | | 0 | | | 1,284 | | | 2,554 | | | 787 | | | 301 | | | 0 | | | 1,453 | | | 2,541 | |
Total pension and OPEB plan assets(d) | $ | 6,769 | | | $ | 5,986 | | | $ | 830 | | | $ | 9,445 | | | $ | 23,030 | | | $ | 5,955 | | | $ | 5,440 | | | $ | 487 | | | $ | 9,369 | | | $ | 21,251 | |
__________
(a)See Note 418—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.
(b)Includes derivative instruments of $2 million for the years ended December 31, 2020 and 2019, which have total notional amounts of $6,879 million and $6,668 million at December 31, 2020 and 2019, respectively. The notional principal
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.
(c)Includes investments in equities sold short held in investment vehicles primarily to hedge the equity option component of its convertible debt. Pension equities sold short totaled $(96) million and $(75) million as of December 31, 2020 and 2019, respectively. OPEB equities sold short totaled $(42) million and $(35) million as of December 31, 2020 and 2019, respectively.
(d)Excludes net liabilities of $132 million and $120 million at December 31, 2020 and 2019, respectively, which include certain derivative assets that have notional amounts of $239 million and $632 million at December 31, 2020 and 2019, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases and interest and dividends receivable.
The following table presents the reconciliation of Level 3 assets and liabilities for Exelon measured at fair value for pension and OPEB plans for the years ended December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Fixed Income | | Equities | | Private
Credit | | Total |
| Pension Assets | | | | | | | | | | | | | |
| Balance as of January 1, 2020 | | | | | | | $ | 245 | | | $ | 5 | | | $ | 237 | | | $ | 487 | |
| Actual return on plan assets: | | | | | | | | | | | | | |
Relating to assets still held at the
reporting date | | | | | | | 19 | | | (3) | | | 15 | | | 31 | |
| | | | | | | | | | | | | |
| Purchases, sales and settlements: | | | | | | | | | | | | | |
| Purchases | | | | | | | 34 | | | 0 | | | 24 | | | 58 | |
| | | | | | | | | | | | | |
Settlements(a) | | | | | | | (3) | | | 0 | | | (42) | | | (45) | |
Transfers into Level 3(b) | | | | | | | 299 | | | 0 | | | 0 | | | 299 | |
| Balance as of December 31, 2020 | | | | | | | $ | 594 | | | $ | 2 | | | $ | 234 | | | $ | 830 | |
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| | | | | | | Fixed Income | | Equities | | Private
Credit | | Total |
| Pension Assets | | | | | | | | | | | | | |
| Balance as of January 1, 2019 | | | | | | | $ | 216 | | | $ | 2 | | | $ | 268 | | | $ | 486 | |
| Actual return on plan assets: | | | | | | | | | | | | | |
Relating to assets still held at the reporting date | | | | | | | 28 | | | 3 | | | 28 | | | 59 | |
Relating to assets sold during the period | | | | | | | (7) | | | 0 | | | 0 | | | (7) | |
| Purchases, sales and settlements: | | | | | | | | | | | | | |
| Purchases | | | | | | | 26 | | | 0 | | | 41 | | | 67 | |
| Sales | | | | | | | (4) | | | 0 | | | 0 | | | (4) | |
Settlements(a) | | | | | | | (2) | | | 0 | | | (100) | | | (102) | |
| Transfers out of Level 3 | | | | | | | (12) | | | 0 | | | 0 | | | (12) | |
| Balance as of December 31, 2019 | | | | | | | $ | 245 | | | $ | 5 | | | $ | 237 | | | $ | 487 | |
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__________
(a)Represents cash settlements only.
(b)In 2020, a contract was terminated for a certain fixed income commingled fund resulting in the ownership of certain fixed income securities which led to a transfer into Level 3 from not subject to leveling of $299 million.
Valuation Techniques Used to Determine Fair Value
The techniques used to fair value the pension and OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real estate, and private credit investments are the same as the valuation techniques for these types of investments in NDTFs. See Cash Equivalents and NDT Fund Investments in Note 18 - Fair Value of Financial Assets and Liabilities for further information.
Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate.
Defined Contribution Savings Plan (All Registrants)
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2020, 2019, and 2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2020 | $ | 158 | | | $ | 63 | | | $ | 36 | | | $ | 12 | | | $ | 13 | | | 14 | | | $ | 4 | | | $ | 3 | | | $ | 3 | |
| 2019 | 161 | | | 73 | | | 35 | | | 11 | | | 12 | | | 13 | | | 3 | | | 3 | | | 2 | |
| 2018 | 179 | | | 86 | | | 37 | | | 9 | | | 12 | | | 13 | | | 3 | | | 2 | | | 2 | |
16. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange risk related to ongoing business operations.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings at Generation and are offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settles and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.
Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.
Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd are downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
Commodity Price Risk (All Registrants)
Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels, and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.
Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.
Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.
| | | | | | | | | | | |
| Registrant | Commodity | Accounting Treatment | Hedging Instrument |
| ComEd | Electricity | NPNS | Fixed price contracts based on all requirements in the IPA procurement plans. |
| Electricity | Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a) | 20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year. |
PECO(b) | Gas | NPNS | Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales. |
| BGE | Electricity | NPNS | Fixed price contracts for all SOS requirements through full requirements contracts. |
| Gas | NPNS | Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. |
| Pepco | Electricity | NPNS | Fixed price contracts for all SOS requirements through full requirements contracts. |
| DPL | Electricity | NPNS | Fixed price contracts for all SOS requirements through full requirements contracts. |
| Gas | NPNS | Fixed and Index priced contracts through full requirements contracts. |
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(c) | Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections. |
| ACE | Electricity | NPNS | Fixed price contracts for all BGS requirements through full requirements contracts. |
_________
(a)See Note 3—Regulatory Matters for additional information.
(b)As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.
(c)The fair value of the DPL economic hedge is not material as of December 31, 2020 and 2019 and is not presented in the fair value tables below.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of December 31, 2020 and 2019:
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| Exelon | | Generation | | ComEd | | | | | |
| December 31, 2020 | Total
Derivatives | | Economic
Hedges | | Proprietary
Trading | | Collateral (a)(b) | | Netting(a) | | Subtotal | | Economic
Hedges | | | | | | | | | |
| Mark-to-market derivative assets (current assets) | $ | 639 | | | $ | 2,757 | | | $ | 40 | | | $ | 103 | | | $ | (2,261) | | | $ | 639 | | | $ | 0 | | | | | | | | | | |
| Mark-to-market derivative assets (noncurrent assets) | 554 | | | 1,501 | | | 4 | | | 64 | | | (1,015) | | | 554 | | | 0 | | | | | | | | | | |
| Total mark-to-market derivative assets | 1,193 | | | 4,258 | | | 44 | | | 167 | | | (3,276) | | | 1,193 | | | 0 | | | | | | | | | | |
| Mark-to-market derivative liabilities (current liabilities) | (293) | | | (2,629) | | | (23) | | | 131 | | | 2,261 | | | (260) | | | (33) | | | | | | | | | | |
| Mark-to-market derivative liabilities (noncurrent liabilities) | (472) | | | (1,335) | | | (2) | | | 118 | | | 1,015 | | | (204) | | | (268) | | | | | | | | | | |
| Total mark-to-market derivative liabilities | (765) | | | (3,964) | | | (25) | | | 249 | | | 3,276 | | | (464) | | | (301) | | | | | | | | | | |
| Total mark-to-market derivative net assets (liabilities) | $ | 428 | | | $ | 294 | | | $ | 19 | | | $ | 416 | | | $ | 0 | | | $ | 729 | | | $ | (301) | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2019 | | | | | | | | | | | | | | | | | | | | | | |
| Mark-to-market derivative assets (current assets) | $ | 675 | | | $ | 3,506 | | | $ | 72 | | | $ | 287 | | | $ | (3,190) | | | $ | 675 | | | $ | 0 | | | | | | | | | | |
| Mark-to-market derivative assets (noncurrent assets) | 508 | | | 1,238 | | | 25 | | | 122 | | | (877) | | | 508 | | | 0 | | | | | | | | | | |
| Total mark-to-market derivative assets | 1,183 | | | 4,744 | | | 97 | | | 409 | | | (4,067) | | | 1,183 | | | 0 | | | | | | | | | | |
| Mark-to-market derivative liabilities (current liabilities) | (236) | | | (3,713) | | | (38) | | | 357 | | | 3,190 | | | (204) | | | (32) | | | | | | | | | | |
| Mark-to-market derivative liabilities (noncurrent liabilities) | (380) | | | (1,140) | | | (11) | | | 163 | | | 877 | | | (111) | | | (269) | | | | | | | | | | |
| Total mark-to-market derivative liabilities | (616) | | | (4,853) | | | (49) | | | 520 | | | 4,067 | | | (315) | | | (301) | | | | | | | | | | |
| Total mark-to-market derivative net assets (liabilities) | $ | 567 | | | $ | (109) | | | $ | 48 | | | $ | 929 | | | $ | 0 | | | $ | 868 | | | $ | (301) | | | | | | | | | | |
_________
(a)Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit, and other forms of non-cash collateral. These amounts are not material and not reflected in the table above.
(b)Of the collateral posted, $209 million and $511 million represents variation margin on the exchanges at December 31, 2020 and 2019, respectively.
Economic Hedges (Commodity Price Risk)
Generation. For the years ended December 31, 2020, 2019, and 2018, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
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| | Gain (Loss) |
| Income Statement Location | | 2020 | | 2019 | | 2018 |
| | |
| Operating revenues | | $ | 112 | | | $ | 0 | | | $ | (270) | |
| Purchased power and fuel | | 168 | | | (204) | | | (47) | |
| Total Exelon and Generation | | $ | 280 | | | $ | (204) | | | $ | (317) | |
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of December 31, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% for 2021.
Proprietary Trading (Commodity Price Risk)
Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the years ended December 31, 2020, 2019, and 2018, net pre-tax commodity mark-to-market gains and losses for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.
Interest Rate and Foreign Exchange Risk (Exelon and Generation)
Exelon and Generation utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The notional amounts were $516 million and $1,269 million at December 31, 2020 and 2019, respectively, for Exelon and $516 million and $569 million at December 31, 2020 and 2019, respectively, for Generation.
Generation utilizes foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, which are treated as economic hedges. The notional amounts were $149 million and $231 million at December 31, 2020 and 2019, respectively.
The mark-to-market derivative assets and liabilities as of December 31, 2020 and 2019 and the mark-to-market gains and losses for the years ended December 31, 2020, 2019, and 2018 were not material for Exelon and Generation.
Credit Risk (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date.
Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2020. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges.
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| Rating as of December 31, 2020 | Total
Exposure
Before Credit
Collateral | | Credit Collateral(a) | | Net
Exposure | | Number of
Counterparties
Greater than 10%
of Net Exposure | | Net Exposure of
Counterparties
Greater than 10%
of Net Exposure |
| Investment grade | $ | 577 | | | $ | 27 | | | $ | 550 | | | 0 | | | $ | 0 | |
| Non-investment grade | 32 | | | 0 | | | 32 | | | | | |
| No external ratings | | | | | | | | | |
| Internally rated — investment grade | 165 | | | 1 | | | 164 | | | | | |
| Internally rated — non-investment grade | 80 | | | 28 | | | 52 | | | | | |
| Total | $ | 854 | | | $ | 56 | | | $ | 798 | | | 0 | | | $ | 0 | |
| | | | | |
| Net Credit Exposure by Type of Counterparty | As of December 31, 2020 |
| Financial institutions | $ | 15 | |
| Investor-owned utilities, marketers, power producers | 607 | |
| Energy cooperatives and municipalities | 138 | |
| Other | 38 | |
| Total | $ | 798 | |
__________
(a)As of December 31, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $25 million of letters of credit. The credit collateral does not include non-liquid collateral.
Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of December 31, 2020, the Utility Registrants’ counterparty credit risk with suppliers was not material.
Credit-Risk-Related Contingent Features (All Registrants)
Generation. As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
The aggregate fair value of all derivative instruments with credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:
| | | | | | | | | | | | | | |
| | As of December 31, |
| Credit-Risk Related Contingent Features | | 2020 | | 2019 |
Gross fair value of derivative contracts containing this feature(a) | | $ | (834) | | | $ | (956) | |
Offsetting fair value of in-the-money contracts under master netting arrangements(b) | | 537 | | | 649 | |
Net fair value of derivative contracts containing this feature(c) | | $ | (297) | | | $ | (307) | |
__________
(a)Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements.
(b)Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which Generation could potentially be required to post collateral.
(c)Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
As of December 31, 2020 and 2019, Exelon and Generation posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
| | | | | | | | | | | | | | |
| | As of December 31, |
| | 2020 | | 2019 |
| Cash collateral posted | | $ | 511 | | | $ | 982 | |
| Letters of credit posted | | 226 | | | 264 | |
| Cash collateral held | | 110 | | | 103 | |
| Letters of credit held | | 40 | | | 112 | |
| Additional collateral required in the event of a credit downgrade below investment grade | | 1,432 | | | 1,509 | |
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.
Utility Registrants
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral.
PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of December 31, 2020, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of December 31, 2020, they could have been required to post incremental collateral to their counterparties of $34 million, $54 million, and $9 million, respectively.
17. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and borrowings from the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Commercial Paper
The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Maximum
Program Size at
December 31, | | Outstanding
Commercial
Paper at
December 31, | | Average Interest Rate on
Commercial Paper Borrowings at December 31, |
| Commercial Paper Issuer | 2020(a)(b)(c) | | 2019(a)(b)(c) | | 2020 | | 2019 | | 2020 | | 2019 |
Exelon(d) | $ | 9,000 | | | $ | 9,000 | | | $ | 1,031 | | | $ | 870 | | | 0.25 | % | | 2.25 | % |
| Generation | 5,300 | | | 5,300 | | | 340 | | | 320 | | | 0.27 | % | | 1.84 | % |
| ComEd | 1,000 | | | 1,000 | | | 323 | | | 130 | | | 0.23 | % | | 2.38 | % |
| PECO | 600 | | | 600 | | | 0 | | | 0 | | | 0 | % | | 2.39 | % |
| BGE | 600 | | | 600 | | | 0 | | | 76 | | | 0 | % | | 2.46 | % |
PHI(e) | 900 | | | 900 | | | 368 | | | 208 | | | 0.24 | % | | N/A |
| Pepco | 300 | | | 300 | | | 35 | | | 82 | | | 0.22 | % | | 2.56 | % |
| DPL | 300 | | | 300 | | | 146 | | | 56 | | | 0.24 | % | | 2.02 | % |
| ACE | 300 | | | 300 | | | 187 | | | 70 | | | 0.25 | % | | 2.43 | % |
__________
(a)Excludes $1,500 million and $1,400 million in bilateral credit facilities at December 31, 2020 and 2019, respectively, and $144 million and $159 million in credit facilities for project finance at December 31, 2020 and 2019, respectively. These credit facilities do not back Generation's commercial paper program.
(b)At December 31, 2020, excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $38 million, $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. These facilities expire on October 8, 2021. These facilities are solely utilized to issue letters of credit. At December 31, 2019, excludes $142 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $44 million, $33 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively.
(c)Pepco, DPL, and ACE's revolving credit facility has the ability to flex to $500 million, $500 million, and $350 million, respectively. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL, or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.
(d)Includes revolving credit agreement at Exelon Corporate with a maximum program size of $600 million at both December 31, 2020 and 2019, respectively. Exelon Corporate had 0 outstanding commercial paper as of December 31, 2020 and $136 million at 2019 with an average interest rate on commercial paper borrowings of 1.92%.
(e)Represents the consolidated amounts of Pepco, DPL, and ACE.
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. A registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
At December 31, 2020, the Registrants had the following aggregate bank commitments, credit facility borrowings, and available capacity under their respective credit facilities:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Available Capacity at December 31, 2020 |
Borrower(a) | Facility Type | | Aggregate Bank
Commitment(b) | | Facility Draws | | Outstanding
Letters of Credit | | Actual | | To Support Additional Commercial
Paper(c) |
Exelon(c) | Syndicated Revolver / Bilaterals / Project Finance | | $ | 10,644 | | | $ | 0 | | | $ | 1,230 | | | $ | 9,414 | | | $ | 7,698 | |
| Generation | Syndicated Revolver | | 5,300 | | | 0 | | | 262 | | | 5,038 | | | 4,698 | |
| Generation | Bilaterals | | 1,500 | | | 0 | | | 840 | | | 660 | | | 0 | |
| Generation | Project Finance | | 144 | | | 0 | | | 119 | | | 25 | | | 0 | |
| ComEd | Syndicated Revolver | | 1,000 | | | 0 | | | 2 | | | 998 | | | 675 | |
| PECO | Syndicated Revolver | | 600 | | | 0 | | | 0 | | | 600 | | | 600 | |
| BGE | Syndicated Revolver | | 600 | | | 0 | | | 0 | | | 600 | | | 600 | |
| PHI | Syndicated Revolver | | 900 | | | 0 | | | 1 | | | 899 | | | 531 | |
| Pepco | Syndicated Revolver | | 300 | | | 0 | | | 1 | | | 299 | | | 264 | |
| DPL | Syndicated Revolver | | 300 | | | 0 | | | 0 | | | 300 | | | 154 | |
| ACE | Syndicated Revolver | | 300 | | | 0 | | | 0 | | | 300 | | | 113 | |
__________
(a)On May 26, 2018, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2023.
(b)Excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $38 million, $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. These facilities expire on October 8, 2021. These facilities are solely utilized to issue letters of credit. As of December 31, 2020, letters of credit issued under these facilities totaled $5 million, $5 million, and $2 million for Generation, ComEd, and BGE, respectively.
(c)Includes $600 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $6 million outstanding letters of credit at December 31, 2020. Exelon Corporate had $594 million in available capacity to support additional commercial paper at December 31, 2020.
On March 19, 2020, Generation borrowed $1.5 billion on its revolving credit facility due to disruptions in the commercial paper markets as a result of COVID-19. The funds were used to refinance commercial paper. Generation repaid the $1.5 billion borrowed on the revolving credit facility on April 3, 2020.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a 12-month term loan agreement for $500 million, which was renewed annually on March 22, 2018, March 20, 2019, and March 19, 2020, respectively. The loan agreement will expire on March 18, 2021. Pursuant to the loan agreement, as of December 31, 2020, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loans beared interest at LIBOR plus 0.95% as of December 31, 2019 as part of the March 20, 2019 renewal. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.
On March 19, 2020, Generation entered into a term loan agreement for $200 million. The loan agreement has an expiration of March 18, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.50% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.
On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement has an expiration of March 30, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.75% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
On January 25, 2021, ComEd entered into two 90-day term loan agreements of $125 million each with variable interest rates of LIBOR plus 0.50% and LIBOR plus 0.75%, respectively.
Revolving Credit Agreements
On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility at a variable interest rate of LIBOR plus 1.75%. This facility will be used by Exelon as an additional source of short-term liquidity as needed.
Bilateral Credit Agreements
The following table reflects the bilateral credit agreements at December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant | | Date Initiated | | Latest Amendment Date | | Maturity Date(a) | | Amount |
Generation(b) | | October 26, 2012 | | October 23, 2020 | | October 22, 2021 | | $ | 200 | |
Generation(c) | | January 11, 2013 | | January 4, 2019 | | March 1, 2021 | | 100 |
Generation(c) | | January 5, 2016 | | January 4, 2019 | | April 5, 2021 | | 150 |
Generation(c) | | February 21, 2019 | | N/A | | March 31, 2021 | | 100 |
Generation(c) | | October 25, 2019 | | N/A | | N/A | | 200 |
Generation(c) | | October 25, 2019 | | N/A | | N/A | | 100 |
Generation(c) | | November 20, 2019 | | N/A | | N/A | | 300 |
Generation(c) | | November 21, 2019 | | N/A | | N/A | | 150 |
Generation(c) | | November 21, 2019 | | N/A | | November 21, 2021 | | 100 |
Generation(c) | | May 15, 2020 | | N/A | | N/A | | 100 |
__________
(a)Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement.
(b)Bilateral credit facility relates to CENG, which is incorporated within Generation, and supports the issuance of letters of credit and funding for working capital and does not back Generation's commercial paper program. During the second and third quarters of 2020, CENG drew on its bilateral credit facility. As of December 31, 2020, there was 0 outstanding balance at this facility.
(c)Bilateral credit agreements solely support the issuance of letters of credit and do not back Generation's commercial paper program.
Borrowings under Exelon’s, Generation’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon(a) | | Generation | | ComEd | | PECO | | BGE | | | | Pepco | | DPL | | ACE |
| Prime based borrowings | 0 - 27.5 | | 27.5 | | | — | | | — | | | — | | | | | 7.5 | | | — | | | 7.5 | |
| LIBOR-based borrowings | 90.0 - 127.5 | | 127.5 | | | 100.0 | | | 90.0 | | | 90.0 | | | | | 107.5 | | | 100.0 | | | 107.5 | |
__________
(a)Includes interest rate adders at Exelon Corporate of 27.5 and 127.5 for prime and LIBOR-based borrowings, respectively.
If any registrant loses its investment grade rating, the maximum adders for prime rate borrowings and LIBOR-based rate borrowings would be 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower.
ComponentsNDT Funds
NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of Income Tax Expense or Benefitany other unit.
Income tax expense (benefit)The NDT funds associated with Generation's nuclear units have been funded with amounts collected from continuing operationsthe previous owners and their respective utility customers. PECO is comprisedauthorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the following components:former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a decrease from the previously approved annual collection of approximately $24 million primarily due to the removal of the collections for Limerick Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the new rates became effective January 1, 2018.
Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party (see Zion Station Decommissioning below) and the CENG units, where any shortfall is required to be funded by both Generation and EDF. Generation, through PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from utility customers for any of Generation's other nuclear units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to NDT funds that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, 2018 | | |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Included in operations: | | | | | | | | | | | | | | | | | |
| Federal | | | | | | | | | | | | | | | | | |
| Current | $ | 226 |
| | $ | 337 |
| | $ | (63 | ) | | $ | 11 |
| | $ | (5 | ) | | $ | (4 | ) | | $ | 28 |
| | $ | (3 | ) | | $ | (14 | ) |
| Deferred | (98 | ) | | (347 | ) | | 145 |
| | 10 |
| | 47 |
| | 24 |
| | (21 | ) | | 13 |
| | 18 |
|
| Investment tax credit amortization | (24 | ) | | (21 | ) | | (2 | ) | | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
|
| State | | | | | | | | | | | | | | | | | |
| Current | (1 | ) | | 6 |
| | (29 | ) | | 1 |
| | — |
| | 7 |
| | — |
| | — |
| | — |
|
| Deferred | 17 |
| | (83 | ) | | 117 |
| | (16 | ) | | 32 |
| | 9 |
| | 6 |
| | 12 |
| | 8 |
|
| Total | $ | 120 |
| | $ | (108 | ) | | $ | 168 |
| | $ | 6 |
| | $ | 74 |
| | $ | 35 |
| | $ | 13 |
| | $ | 22 |
| | $ | 12 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, 2017(a) | | |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Included in operations: | | | | | | | | | | | | | | | | | |
| Federal | | | | | | | | | | | | | | | | | |
| Current | $ | 194 |
| | $ | 584 |
| | $ | (191 | ) | | $ | 71 |
| | $ | 74 |
| | $ | (60 | ) | | $ | (20 | ) | | $ | (24 | ) | | $ | (12 | ) |
| Deferred | (471 | ) | | (2,005 | ) | | 523 |
| | 28 |
| | 101 |
| | 250 |
| | 114 |
| | 82 |
| | 34 |
|
| Investment tax credit amortization | (25 | ) | | (21 | ) | | (2 | ) | | — |
| | (1 | ) | | (1 | ) | | — |
| | — |
| | — |
|
| State | | | | | | | | | | | | | | | | |
|
| Current | 14 |
| | 65 |
| | (49 | ) | | 14 |
| | (5 | ) | | (4 | ) | | (2 | ) | | — |
| | — |
|
| Deferred | 162 |
| | 1 |
| | 136 |
| | (9 | ) | | 49 |
| | 32 |
| | 13 |
| | 13 |
| | 4 |
|
| Total | $ | (126 | ) | | $ | (1,376 | ) | | $ | 417 |
| | $ | 104 |
| | $ | 218 |
| | $ | 217 |
| | $ | 105 |
| | $ | 71 |
| | $ | 26 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| | For the Year Ended December 31, 2016(a) | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
| Included in operations: | | | | | | | | | | | | | | | | | | | | |
| Federal | | | | | | | | | | | | | | | | | | | | |
| Current | $ | 60 |
| | $ | 513 |
| | $ | (135 | ) | | $ | 63 |
| | $ | 51 |
| | $ | (118 | ) | | $ | (88 | ) | | $ | (26 | ) | | $ | (281 | ) | | | $ | — |
|
| Deferred | 600 |
| | (254 | ) | | 379 |
| | 72 |
| | 88 |
| | 136 |
| | 97 |
| | 22 |
| | 283 |
| | | 10 |
|
| Investment tax credit amortization | (24 | ) | | (20 | ) | | (2 | ) | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) | | | — |
|
| State | | | | | | | | | | | | | | | | | | | |
|
| Current | 39 |
| | 45 |
| | (4 | ) | | 9 |
| | 5 |
| | 7 |
| | 1 |
| | — |
| | (11 | ) | | | — |
|
| Deferred | 78 |
| | (2 | ) | | 63 |
| | 5 |
| | 31 |
| | 16 |
| | 12 |
| | — |
| | 13 |
| | | 7 |
|
| Total | $ | 753 |
| | $ | 282 |
| | $ | 301 |
| | $ | 149 |
| | $ | 174 |
| | $ | 41 |
| | $ | 22 |
| | $ | (4 | ) | | $ | 3 |
| | | $ | 17 |
|
__________
| |
(a) | Exelon retrospectively adopted the new standard Revenue from Contracts with Customers. The standard was adopted as of January 1, 2018. Components of income tax expense or benefit are recast to reflect the impact of the new standard. |
Rate Reconciliation
The effective income tax rate from continuing operations variesthat the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the U.S. federal statutory rate principally duefunds for non-decommissioning activities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management and decommissioning) is to be paid to the following:Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities.
At December 31, 2020 and 2019, Exelon and Generation had NDT funds totaling $14,599 millionand $13,353 million, respectively. The NDT funds include $134 million and $163 million for the current portion of the NDT at December 31, 2020 and 2019, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 24 — Supplemental Financial Information for additional information on activities of the NDT funds.
Accounting Implications of the Regulatory Agreements with ComEd and PECO
Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are recorded by Generation and the corresponding regulated utility as a component of the intercompany and regulatory balances on the balance sheet. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.
For the former PECO units, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from PECO customers in the event of a shortfall and the obligation for Generation to ultimately return any excess funds to PECO customers (on an aggregate basis for all seven units),decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables or noncurrent receivables to affiliates at Generation with PECO recording an equal noncurrent affiliate receivable from or payable to Generation and a corresponding regulatory liability or regulatory asset. Any changes to the existing PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s financial statements could be material.
For the former ComEd units, given no further recovery from ComEd customers is permitted and Generation retains an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, the offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results with Generation recognizing an intercompany payable to ComEd while ComEd records an intercompany receivable from Generation with a corresponding regulatory liability.However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible and accounting for decommissioning-related activities at Generation for that unit would not be offset, and the impact to Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income could be material during such periods.
As of December 31, 2020, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are currently offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, 2018 |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| U.S. Federal statutory rate | 21.0 | % |
| 21.0 | % |
| 21.0 | % |
| 21.0 | % |
| 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
| State income taxes, net of Federal income tax benefit | 0.6 |
| | (16.6 | ) | | 8.3 |
| | (2.6 | ) | | 6.6 |
| | 3.0 |
| | 2.2 |
| | 6.7 |
| | 7.4 |
|
| Qualified NDT fund income | (1.9 | ) | | (11.8 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.2 | ) | | (6.5 | ) | | (0.2 | ) | | (0.1 | ) | | (0.1 | ) | | (0.2 | ) | | (0.1 | ) | | (0.3 | ) | | (0.4 | ) |
| Plant basis differences | (3.5 | ) | | — |
| | (0.2 | ) | | (14.1 | ) | | (1.3 | ) | | (1.6 | ) | | (2.7 | ) | | (0.3 | ) | | (0.5 | ) |
| Production tax credits and other credits | (2.2 | ) | | (13.5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Noncontrolling interests | (1.0 | ) | | (6.1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Excess deferred tax amortization | (8.3 | ) | | — |
| | (9.1 | ) | | (3.2 | ) | | (8.0 | ) | | (14.5 | ) | | (14.8 | ) | | (12.0 | ) | | (14.9 | ) |
| Tax Cuts and Jobs Act of 2017 | 0.9 |
| | 2.7 |
| | (0.1 | ) | | — |
| | — |
| | 0.1 |
| | — |
| | — |
| | — |
|
| Other | 1.0 |
| | 1.3 |
| | 0.5 |
| | 0.3 |
| | 0.9 |
| | 0.3 |
| | 0.2 |
| | 0.4 |
| | 1.2 |
|
| Effective income tax rate | 5.4 | % | | (29.5 | )% | | 20.2 | % | | 1.3 | % | | 19.1 | % | | 8.1 | % | | 5.8 | % | | 15.5 | % | | 13.8 | % |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
See Note 3 — Regulatory Matters and Note 25 — Related Party Transactions for additional information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd, and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.
Zion Station Decommissioning
In 2010, Generation completed an ASA under which ZionSolutions assumed responsibility for decommissioning Zion Station and Generation transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds.
Following ZionSolutions' completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility.
Generation had retained its obligation for the SNF as well as certain NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. As of December 31, 2020, the ARO associated with Zion's SNF storage facility is $175 million and the NDT funds available to fund this obligation are $66 million.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the NRC methodology differ from the ARO recorded in Generation’s and Exelon’s Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees.
Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2020 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).
In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 2020 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain LLRW); (3) the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 4% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.6% to 6.1% (as compared to a historical 5-year annual average pre-tax return of approximately 9.0%).
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, 2017(a) |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| U.S. Federal statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
| State income taxes, net of Federal income tax benefit | 2.3 |
| | 2.9 |
| | 5.7 |
| | 0.6 |
| | 5.4 |
| | 4.8 |
| | 3.2 |
| | 5.4 |
| | 5.6 |
|
| Qualified NDT fund income | 3.8 |
| | 9.9 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Amortization of investment tax credit, including deferred taxes on basis difference | (0.9 | ) | | (2.1 | ) | | (0.2 | ) | | (0.1 | ) | | (0.1 | ) | | (0.2 | ) | | (0.1 | ) | | (0.2 | ) | | (0.4 | ) |
Plant basis differences(b) | (1.7 | ) | | — |
| | 0.3 |
| | (13.8 | ) | | 0.1 |
| | 1.1 |
| | (0.4 | ) | | 2.0 |
| | 3.6 |
|
| Production tax credits and other credits | (1.8 | ) | | (4.7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Like-kind exchange | (1.2 | ) | | — |
| | 1.3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Merger expenses | (3.6 | ) | | (1.2 | ) | | — |
| | — |
| | — |
| | (9.5 | ) | | (6.3 | ) | | (7.8 | ) | | (19.8 | ) |
| FitzPatrick bargain purchase gain | (2.2 | ) | | (5.6 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Tax Cuts and Jobs Act of 2017(c) | (33.1 | ) | | (128.3 | ) | | 0.1 |
| | (2.3 | ) | | 0.9 |
| | 6.4 |
| | 2.7 |
| | 2.5 |
| | 1.6 |
|
| Other | 0.1 |
| | (0.5 | ) | | 0.2 |
| | (0.1 | ) | | 0.2 |
| | (0.1 | ) | | (0.2 | ) | | 0.1 |
| | (0.4 | ) |
| Effective income tax rate | (3.3 | )% | | (94.6 | )% | | 42.4 | % | | 19.3 | % | | 41.5 | % | | 37.5 | % | | 33.9 | % | | 37.0 | % | | 25.2 | % |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial positions may be significantly adversely affected.
Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 for all units, including its shutdown units, except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the April 1, 2019 submittal. On March 31, 2020, Generation filed its annual decommissioning funding status report with the NRC for Generation’s shutdown units (excluding Zion Station for the reason noted above). The annual status report demonstrated adequate decommissioning funding assurance as of December 31, 2019, for all of its shutdown reactors except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO ratepayers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff.
Generation will file its next decommissioning funding status report with the NRC by March 31, 2021. This report will reflect the status of decommissioning funding assurance as of December 31, 2020 and will include the 2021 early retirements of Byron and Dresden. A shortfall could require Exelon to post parental guarantee for Generation’s share of the funding assurance. However, the amount of any required guarantee will ultimately depend on the decommissioning approach adopted at Byron and Dresden, the associated level of costs, and the decommissioning trust fund investment performance going forward.
As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.
Non-Nuclear Asset Retirement Obligations (All Registrants)
Generation has AROs for plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations and other decommissioning-related activities. The Utility Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 — Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| | For the Year Ended December 31, 2016(a) | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL (d) | | ACE (d) | | PHI (d) | | | PHI |
| U.S. Federal statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | | 35.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | | | |
|
State income taxes, net of Federal income tax benefit (e) | 3.3 |
| | 3.2 |
| | 5.6 |
| | 1.3 |
| | 5.0 |
| | 15.7 |
| | 52.7 |
| | 6.2 |
| | 5.8 |
| | | 11.9 |
|
| Qualified NDT fund income | 3.4 |
| | 7.9 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.2 | ) | | (2.3 | ) | | (0.3 | ) | | (0.1 | ) | | (0.1 | ) | | (0.2 | ) | | (3.7 | ) | | 0.8 |
| | 1.4 |
| | | (0.9 | ) |
| Plant basis differences | (4.9 | ) | | — |
| | (0.6 | ) | | (9.6 | ) | | (2.7 | ) | | (22.8 | ) | | (25.5 | ) | | 10.3 |
| | 39.0 |
| | | (13.5 | ) |
| Production tax credits and other credits | (3.6 | ) | | (8.3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Noncontrolling interests | (0.2 | ) | | (0.6 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Statute of limitations expiration | (0.4 | ) | | (1.7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Penalties | 1.9 |
| | — |
| | 4.5 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (0.7 | ) | | | — |
|
| Merger Expenses | 5.6 |
| | 1.1 |
| | — |
| | — |
| | — |
| | 23.5 |
| | 112.9 |
| | (44.9 | ) | | (89.0 | ) | | | 11.1 |
|
Other (f) | (0.7 | ) | | (1.4 | ) | | 0.1 |
| | (1.2 | ) | | — |
| | (1.8 | ) | | (2.2 | ) | | 1.3 |
| | 3.3 |
| | | 3.6 |
|
| Effective income tax rate | 38.2 | % | | 32.9 | % | | 44.3 | % | | 25.4 | % | | 37.2 | % |
| 49.4 | % |
| 169.2 | % |
| 8.7 | % |
| (5.2 | )% |
| | 47.2 | % |
__________
| |
(a) | Exelon retrospectively adopted the new standard Revenue from Contracts with Customers. The standard was adopted as of January 1, 2018. The effective income tax rates are recast to reflect the impact of the new standard. |
| |
(b) | Includes the charges related to the transmission-related income tax regulatory asset for Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE of $35 million, $3 million, $5 million, $27 million, $14 million, $6 million and $7 million, respectively. See Note 4 - Regulatory Matters for additional information. |
| |
(c) | Included are impacts for TCJA other than the corporate rate change, including revisions further limiting tax deductions for compensation of certain highest paid executives, the write-off of foreign tax credit carryforwards, and loss of a 2015 domestic production activities deduction due to an NOL carryback. |
| |
(d) | DPL and ACE recognized a loss before income taxes for the year ended December 31, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through December 31, 2016. As a result, positive percentages represent an income tax benefit for the periods presented. |
| |
(e) | Includes a remeasurement of uncertain state income tax positions for Pepco and DPL. |
| |
(f) | At PECO, includes a cumulative adjustment related to an anticipated gas repairs tax return accounting method change. The method change request was filed and accepted in 2017. No change to the results recorded as of December 31, 2016. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
Tax Differences and Carryforwards
The tax effects of temporary differences and carryforwards, which give rise to significant portionsfollowing table provides a rollforward of the deferred tax assets (liabilities),non-nuclear AROs reflected in the Registrants’ Consolidated Balance Sheets from January 1, 2019 to December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Non-nuclear AROs at January 1, 2019 | $ | 471 | | | $ | 238 | | | $ | 121 | | | $ | 28 | | | $ | 25 | | | $ | 52 | | | $ | 37 | | | $ | 11 | | | $ | 4 | |
| Net increase (decrease) due to changes in, and timing of, estimated future cash flows | 17 | | | 7 | | | 8 | | | 0 | | | (2) | | | 4 | | | 3 | | | 1 | | | 0 | |
| Development projects | 2 | | | 2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Accretion expense(a) | 16 | | | 12 | | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | | 0 | | | 0 | |
| Asset divestitures | (42) | | | (42) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Payments | (4) | | | (1) | | | (1) | | | (1) | | | (1) | | | 0 | | | 0 | | | 0 | | | 0 | |
| Non-nuclear AROs at December 31, 2019 | 460 | | | 216 | | | 129 | | | 28 | | | 23 | | | 57 | | | 41 | | | 12 | | | 4 | |
| Net increase (decrease) due to changes in, and timing of, estimated future cash flows | 7 | | | 2 | | | 0 | | | 2 | | | 1 | | | 1 | | | (3) | | | 2 | | | 2 | |
| Development projects | 1 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Accretion expense(a) | 16 | | | 11 | | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | | 0 | | | 0 | |
| Asset divestitures | (4) | | | (4) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Payments | (9) | | | (4) | | | (1) | | | (2) | | | (2) | | | 0 | | | 0 | | | 0 | | | 0 | |
AROs reclassified to liabilities held for sale(b) | (10) | | | (10) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Non-nuclear AROs at December 31, 2020 | $ | 461 | | | $ | 212 | | | $ | 129 | | | $ | 29 | | | $ | 23 | | | $ | 59 | | | $ | 39 | | | $ | 14 | | | $ | 6 | |
__________
(a)For ComEd, PECO, BGE, PHI, Pepco, and DPL, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
(b)Represents AROs related to Generation's solar business, which were classified as held for sale as a result of the sale agreement. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.
11. Leases(All Registrants)
Lessee
The Registrants have operating and finance leases for which they are the lessees. The following tables outline the significant types of leases at each registrant and other terms and conditions of the lease agreements as of December 31, 20182020. Exelon, Generation, ComEd, PECO, and 2017 are presented below:BGE did not have material finance leases in 2020 or in 2019. PHI, Pepco, DPL, and ACE also did not have material finance leases in 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Contracted generation | ● | | ● | | | | | | | | | | | | | | |
| Real estate | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● |
| Vehicles and equipment | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in years) | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Remaining lease terms | 1-85 | | 1-35 | | 1-4 | | 1-13 | | 1-85 | | 1-11 | | 1-11 | | 1-11 | | 1-7 |
| Options to extend the term | 2-30 | | 2-30 | | 5 | | N/A | | N/A | | 3-30 | | 5 | | 3-30 | | 5 |
| Options to terminate within | 1-12 | | 1-4 | | 2 | | N/A | | 1 | | N/A | | N/A | | N/A | | N/A |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, 2018 |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Plant basis differences | $ | (12,533 | ) | | $ | (2,495 | ) | | $ | (4,059 | ) | | $ | (1,862 | ) | | $ | (1,399 | ) | | $ | (2,577 | ) | | $ | (1,148 | ) | | $ | (743 | ) | | $ | (645 | ) |
| Accrual based contracts | 117 |
| | (44 | ) | | — |
| | — |
| | — |
| | 161 |
| | — |
| | — |
| | — |
|
| Derivatives and other financial instruments | 89 |
| | 35 |
| | 69 |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
| Deferred pension and postretirement obligation | 1,435 |
| | (188 | ) | | (255 | ) | | (26 | ) | | (26 | ) | | (102 | ) | | (78 | ) | | (46 | ) | | (14 | ) |
| Nuclear decommissioning activities | (351 | ) | | (351 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Deferred debt refinancing costs | 234 |
| | 23 |
| | (7 | ) | | — |
| | (3 | ) | | 187 |
| | (4 | ) | | (2 | ) | | (1 | ) |
| Regulatory assets and liabilities | (749 | ) | | — |
| | 300 |
| | (129 | ) | | 172 |
| | (90 | ) | | 58 |
| | 96 |
| | 83 |
|
| Tax loss carryforward | 237 |
| | 78 |
| | — |
| | 18 |
| | 25 |
| | 96 |
| | 12 |
| | 52 |
| | 26 |
|
| Tax credit carryforward | 811 |
| | 816 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Investment in partnerships | (797 | ) | | (775 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other, net | 934 |
| | 239 |
| | 151 |
| | 67 |
| | 12 |
| | 196 |
| | 98 |
| | 17 |
| | 19 |
|
| Deferred income tax liabilities (net) | $ | (10,573 | ) | | $ | (2,662 | ) | | $ | (3,801 | ) | | $ | (1,932 | ) | | $ | (1,219 | ) |
| $ | (2,126 | ) |
| $ | (1,062 | ) |
| $ | (626 | ) |
| $ | (532 | ) |
| Unamortized investment tax credits | (724 | ) | | (700 | ) | | (12 | ) | | (1 | ) | | (3 | ) | | (8 | ) | | (2 | ) | | (2 | ) | | (3 | ) |
Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (11,297 | ) | | $ | (3,362 | ) | | $ | (3,813 | ) | | $ | (1,933 | ) | | $ | (1,222 | ) |
| $ | (2,134 | ) |
| $ | (1,064 | ) |
| $ | (628 | ) |
| $ | (535 | ) |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, 2017 (a) |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Plant basis differences | $ | (12,490 | ) | | $ | (2,819 | ) | | $ | (3,825 | ) | | $ | (1,762 | ) | | $ | (1,368 | ) | | $ | (2,521 | ) | | $ | (1,152 | ) | | $ | (717 | ) | | $ | (607 | ) |
| Accrual based contracts | 150 |
| | (66 | ) | | — |
| | — |
| | — |
| | 216 |
| | — |
| | — |
| | — |
|
| Derivatives and other financial instruments | (85 | ) | | (66 | ) | | (2 | ) | | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
| Deferred pension and postretirement obligation | 1,463 |
| | (205 | ) | | (285 | ) | | (15 | ) | | (29 | ) | | (130 | ) | | (78 | ) | | (51 | ) | | (18 | ) |
| Nuclear decommissioning activities | (553 | ) | | (553 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Deferred debt refinancing costs | 217 |
| | 26 |
| | (8 | ) | | (1 | ) | | (3 | ) | | 203 |
| | (4 | ) | | (2 | ) | | (1 | ) |
| Regulatory assets and liabilities | (688 | ) | | — |
| | 489 |
| | (90 | ) | | 136 |
| | (184 | ) | | 39 |
| | 88 |
| | 86 |
|
| Tax loss carryforward | 344 |
| | 76 |
| | 33 |
| | 9 |
| | 11 |
| | 156 |
| | 40 |
| | 68 |
| | 35 |
|
| Tax credit carryforward | 861 |
| | 868 |
| | 1 |
| | — |
| | — |
| | 6 |
| | — |
| | — |
| | — |
|
| Investment in partnerships | (434 | ) | | (416 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other, net | 746 |
| | 78 |
| | 141 |
| | 71 |
| | 13 |
| | 193 |
| | 94 |
| | 14 |
| | 16 |
|
| Deferred income tax liabilities (net) | $ | (10,469 | ) | | $ | (3,077 | ) | | $ | (3,456 | ) | | $ | (1,788 | ) | | $ | (1,240 | ) |
| $ | (2,058 | ) |
| $ | (1,061 | ) |
| $ | (600 | ) |
| $ | (489 | ) |
| Unamortized investment tax credits | (732 | ) | | (705 | ) | | (13 | ) | | (1 | ) | | (4 | ) | | (8 | ) | | (2 | ) | | (3 | ) | | (4 | ) |
Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (11,201 | ) | | $ | (3,782 | ) | | $ | (3,469 | ) | | $ | (1,789 | ) | | $ | (1,244 | ) |
| $ | (2,066 | ) |
| $ | (1,063 | ) |
| $ | (603 | ) |
| $ | (493 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | |
| Operating lease costs | $ | 292 | | | $ | 194 | | | $ | 3 | | | $ | 1 | | | $ | 33 | | | $ | 46 | | | $ | 11 | | | $ | 13 | | | $ | 6 | |
| Variable lease costs | 241 | | | 234 | | | 1 | | | 0 | | | 1 | | | 2 | | | 1 | | | 1 | | | 0 | |
| Short-term lease costs | 2 | | | 2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Total lease costs (a) | $ | 535 | | | $ | 430 | | | $ | 4 | | | $ | 1 | | | $ | 34 | | | $ | 48 | | | $ | 12 | | | $ | 14 | | | $ | 6 | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | |
| Operating lease costs | $ | 320 | | | $ | 222 | | | $ | 3 | | | $ | 1 | | | $ | 33 | | | $ | 48 | | | $ | 12 | | | $ | 14 | | | $ | 7 | |
| Variable lease costs | 300 | | | 282 | | | 2 | | | 0 | | | 2 | | | 6 | | | 2 | | | 2 | | | 1 | |
| Short-term lease costs | 19 | | | 19 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Total lease costs (a) | $ | 639 | | | $ | 523 | | | $ | 5 | | | $ | 1 | | | $ | 35 | | | $ | 54 | | | $ | 14 | | | $ | 16 | | | $ | 8 | |
__________
| |
(a) | Includes remeasurement impacts related to the TCJA. |
(a)Excludes $48 million, $44 million, $4 million, and $4 million of sublease income recorded at Exelon, Generation, PHI, and DPL, respectively, for the year ended December 31, 2020 and $51 million, $44 million, $7 million, and $7 million of sublease income recorded at Exelon, Generation, PHI, and DPL, respectively, for the year ended December 31, 2019.
PHI, Pepco, DPL, and ACE recorded finance lease costs of $9 million, $3 million, $4 million, and $2 million, respectively, for the year ended December 31, 2020.
The following table presents the Registrants' rental expense under the prior lease accounting guidance for the year ended December 31, 2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rent expense | $ | 670 | | | $ | 558 | | | $ | 7 | | | $ | 10 | | | $ | 35 | | | $ | 48 | | | $ | 10 | | | $ | 13 | | | $ | 8 | |
| | | | | | | | | | | | | | | | | |
__________
(a)Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments table. Payments made under Generation's contracted generation lease agreements totaled $493 million.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Successor | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
| Federal | | | | | | | | | | | | | | | | | | |
| Federal general business credits carryforwards | 811 |
| (a) | 816 |
|
| — |
| | — |
|
| — |
| | — |
| | — |
| | — |
| | — |
| |
| State | | | | | | | | | | | | | | | | | | |
| State net operating losses | 4,103 |
| (b) | 1,544 |
| (b) | — |
| | 224 |
| (c) | 395 |
| (d) | 1,492 |
| (e) | 192 |
| (f) | 772 |
| (g) | 365 |
| (h) |
| Deferred taxes on state tax attributes (net) | 272 |
| | 104 |
| | — |
| | 18 |
| | 26 |
| | 102 |
| | 12 |
| | 52 |
| | 26 |
| |
| Valuation allowance on state tax attributes | 35 |
| | 26 |
| | — |
| | — |
| | 1 |
| | 6 |
| | — |
| | — |
| | — |
| |
__________
| |
(a) | Exelon’s federal general business credit carryforwards will begin expiring in 2033. |
| |
(b) | Exelon’s and Generation's state net operating losses and credit carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2019. |
| |
(c) | PECO's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2031. |
| |
(d) | BGE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2026. |
| |
(e) | PHI's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2036. |
| |
(f) | Pepco's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2033. |
| |
(g) | DPL's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2030. |
| |
(h) | ACE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2031. |
Tabular Reconciliation of Unrecognized Tax Benefits
The following tables provide a reconciliationadditional information regarding the presentation of operating and finance lease ROU assets and lease liabilities within the Registrants’ unrecognized tax benefitsConsolidated Balance Sheets:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Exelon(a) | | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | | | | | | | | | | | | | | | | | |
| Operating lease ROU assets | | | | | | | | | | | | | | | | | |
| Other deferred debits and other assets | $ | 1,064 | | | $ | 726 | | | $ | 7 | | | $ | 1 | | | $ | 46 | | | $ | 241 | | | $ | 49 | | | $ | 54 | | | $ | 15 | |
| | | | | | | | | | | | | | | | | |
| Operating lease liabilities | | | | | | | | | | | | | | | | | |
| Other current liabilities | 213 | | | 132 | | | 3 | | | 0 | | | 45 | | | 31 | | | 6 | | | 9 | | | 4 | |
| Other deferred credits and other liabilities | 1,089 | | | 775 | | | 5 | | | 1 | | | 19 | | | 224 | | | 46 | | | 56 | | | 11 | |
| Total operating lease liabilities | $ | 1,302 | | | $ | 907 | | | $ | 8 | | | $ | 1 | | | $ | 64 | | | $ | 255 | | | $ | 52 | | | $ | 65 | | | $ | 15 | |
| | | | | | | | | | | | | | | | | |
| As of December 31, 2019 | | | | | | | | | | | | | | | | | |
| Operating lease ROU assets | | | | | | | | | | | | | | | | | |
| Other deferred debits and other assets | $ | 1,305 | | | $ | 895 | | | $ | 9 | | | $ | 2 | | | $ | 77 | | | $ | 273 | | | $ | 56 | | | $ | 63 | | | $ | 18 | |
| | | | | | | | | | | | | | | | | |
| Operating lease liabilities | | | | | | | | | | | | | | | | | |
| Other current liabilities | 225 | | | 157 | | | 3 | | | 0 | | | 32 | | | 31 | | | 6 | | | 9 | | | 4 | |
| Other deferred credits and other liabilities | 1,307 | | | 925 | | | 8 | | | 1 | | | 50 | | | 254 | | | 51 | | | 65 | | | 14 | |
| Total operating lease liabilities | $ | 1,532 | | | $ | 1,082 | | | $ | 11 | | | $ | 1 | | | $ | 82 | | | $ | 285 | | | $ | 57 | | | $ | 74 | | | $ | 18 | |
__________
(a)Exelon's and Generation's operating ROU assets and lease liabilities include $387 million and $528 million, respectively, related to contracted generation as of December 31, 2018, 20172020, and 2016:$515 million and $664 million, respectively, as of December 31, 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | | | | | | | | | | | | | | | | | |
| Finance lease ROU assets | | | | | | | | | | | | | | | | | |
| Plant, property and equipment, net | | | | | | | | | | | $ | 50 | | | $ | 17 | | | $ | 20 | | | $ | 13 | |
| | | | | | | | | | | | | | | | | |
| Finance lease liabilities | | | | | | | | | | | | | | | | | |
| Long-term debt due within one year | | | | | | | | | | | 7 | | | 2 | | | 3 | | | 2 | |
| Long-term debt | | | | | | | | | | | 43 | | | 15 | | | 17 | | | 11 | |
| Total finance lease liabilities | | | | | | | | | | | $ | 50 | | | $ | 17 | | | $ | 20 | | | $ | 13 | |
The weighted average remaining lease terms, in years, for operating and finance leases were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | 10.1 | | 10.5 | | 3.8 | | 4.2 | | 8.3 | | 8.2 | | 9.1 | | 9.1 | | 4.0 |
| As of December 31, 2019 | 10.1 | | 10.6 | | 4.6 | | 4.4 | | 5.4 | | 9.0 | | 9.8 | | 9.7 | | 4.7 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Unrecognized tax benefits at January 1, 2018 | $ | 743 |
| | $ | 468 |
| | $ | 2 |
| | $ | — |
| | $ | 120 |
| | $ | 125 |
| | $ | 59 |
| | $ | 21 |
| | $ | 14 |
|
| Change to positions that only affect timing | 15 |
| | 15 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Increases based on tax positions prior to 2018 | 30 |
| | 21 |
| | — |
| | — |
| | — |
| | 8 |
| | 7 |
| | 1 |
| | — |
|
| Decreases based on tax positions prior to 2018 | (251 | ) | | (36 | ) | | — |
| | — |
| | (120 | ) | | (88 | ) | | (66 | ) | | (22 | ) | | — |
|
| Decrease from settlements with taxing authorities | (53 | ) | | (53 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Decreases from expiration of statute of limitations | (7 | ) | | (7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Unrecognized tax benefits at December 31, 2018 | $ | 477 |
| | $ | 408 |
| | $ | 2 |
| | $ | — |
| | $ | — |
|
| $ | 45 |
|
| $ | — |
|
| $ | — |
|
| $ | 14 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Unrecognized tax benefits at January 1, 2017 | $ | 916 |
| | $ | 490 |
| | $ | (12 | ) | | $ | — |
| | $ | 120 |
| | $ | 172 |
| | $ | 80 |
| | $ | 37 |
| | $ | 22 |
|
| Increases based on tax positions prior to 2017 | 28 |
| | — |
| | 14 |
| | — |
| | — |
| | 14 |
| | — |
| | — |
| | 14 |
|
| Decreases based on tax positions prior to 2017 | (196 | ) | | (17 | ) | | — |
| | — |
| | — |
| | (61 | ) | | (21 | ) | | (16 | ) | | (22 | ) |
| Decrease from settlements with taxing authorities | (5 | ) | | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Unrecognized tax benefits at December 31, 2017 | $ | 743 |
|
| $ | 468 |
|
| $ | 2 |
|
| $ | — |
|
| $ | 120 |
|
| $ | 125 |
|
| $ | 59 |
|
| $ | 21 |
|
| $ | 14 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Unrecognized tax benefits at January 1, 2016 | $ | 1,078 |
| | $ | 534 |
| | $ | 142 |
| | $ | — |
| | $ | 120 |
| | $ | 22 |
| | $ | 8 |
| | $ | 3 |
| | $ | — |
|
| Merger balance transfer | 22 |
| | 5 |
| | — |
| | — |
| | — |
| | (5 | ) | | — |
| | — |
| | — |
|
| Increases based on tax positions related to 2016 | 108 |
| | 10 |
| | — |
| | — |
| | — |
| | 59 |
| | 21 |
| | 16 |
| | 22 |
|
| Change to positions that only affect timing | (332 | ) | | (12 | ) | | (154 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Increases based on tax positions prior to 2016 | 88 |
| | — |
| | — |
| | — |
| | — |
| | 96 |
| | 51 |
| | 18 |
| | — |
|
| Decreases based on tax positions prior to 2016 | (21 | ) | | (20 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Decreases from settlements with taxing authorities | (27 | ) | | (27 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Unrecognized tax benefits at December 31, 2016 | $ | 916 |
| | $ | 490 |
| | $ | (12 | ) | | $ | — |
| | $ | 120 |
|
| $ | 172 |
|
| $ | 80 |
|
| $ | 37 |
|
| $ | 22 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | | | | | | | | | | | 6.5 | | 6.3 | | 6.5 | | 6.5 |
| | | | | | | | | | | | | | | | | |
As a resultThe weighted average discount rates for operating and finance leases were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | 4.7 | % | | 4.9 | % | | 3.0 | % | | 2.9 | % | | 3.8 | % | | 4.2 | % | | 4.0 | % | | 4.0 | % | | 3.5 | % |
| As of December 31, 2019 | 4.6 | % | | 4.8 | % | | 3.0 | % | | 3.2 | % | | 3.6 | % | | 4.2 | % | | 4.0 | % | | 4.0 | % | | 3.6 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | | | | | | | | | | | 2.5 | % | | 2.6 | % | | 2.4 | % | | 2.4 | % |
| | | | | | | | | | | | | | | | | |
Future minimum lease payments for operating and finance leases as of a court decision issued in July 2018 to an unrelated taxpayer, Exelon's and Generation’s unrecognized federal and state tax benefits increasedDecember 31, 2020 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2021 | $ | 239 | | | $ | 145 | | | $ | 3 | | | $ | 1 | | | $ | 46 | | | $ | 40 | | | $ | 8 | | | $ | 11 | | | $ | 5 | |
| 2022 | 177 | | | 113 | | | 2 | | | 0 | | | 16 | | | 39 | | | 8 | | | 10 | | | 4 | |
| 2023 | 146 | | | 100 | | | 1 | | | 0 | | | 1 | | | 38 | | | 7 | | | 9 | | | 3 | |
| 2024 | 141 | | | 98 | | | 1 | | | 0 | | | 0 | | | 36 | | | 6 | | | 8 | | | 2 | |
| 2025 | 140 | | | 99 | | | 1 | | | 0 | | | 0 | | | 33 | | | 6 | | | 7 | | | 2 | |
| Remaining years | 834 | | | 640 | | | 0 | | | 0 | | | 18 | | | 120 | | | 28 | | | 35 | | | 0 | |
| Total | 1,677 | | | 1,195 | | | 8 | | | 1 | | | 81 | | | 306 | | | 63 | | | 80 | | | 16 | |
| Interest | 375 | | | 288 | | | 0 | | | 0 | | | 17 | | | 51 | | | 11 | | | 15 | | | 1 | |
| Total operating lease liabilities | $ | 1,302 | | | $ | 907 | | | $ | 8 | | | $ | 1 | | | $ | 64 | | | $ | 255 | | | $ | 52 | | | $ | 65 | | | $ | 15 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| Year | | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| 2021 | | | | | | | | | | | $ | 8 | | | $ | 3 | | | $ | 3 | | | $ | 2 | |
| 2022 | | | | | | | | | | | 8 | | | 3 | | | 3 | | | 2 | |
| 2023 | | | | | | | | | | | 8 | | | 3 | | | 3 | | | 2 | |
| 2024 | | | | | | | | | | | 8 | | | 3 | | | 3 | | | 2 | |
| 2025 | | | | | | | | | | | 8 | | | 3 | | | 3 | | | 2 | |
| Remaining years | | | | | | | | | | | 13 | | | 3 | | | 6 | | | 4 | |
| Total | | | | | | | | | | | 53 | | | 18 | | | 21 | | | 14 | |
| Interest | | | | | | | | | | | 3 | | | 1 | | | 1 | | | 1 | |
| Total finance lease liabilities | | | | | | | | | | | $ | 50 | | | $ | 17 | | | $ | 20 | | | $ | 13 | |
Cash paid for amounts included in the third quartermeasurement of 2018 by approximately $71 million. Approximately $20 millionoperating and finance lease liabilities were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating cash flows from operating leases |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | $ | 271 | | | $ | 204 | | | $ | 3 | | | $ | 1 | | | $ | 20 | | | $ | 39 | | | $ | 8 | | | $ | 9 | | | $ | 4 | |
| For the year ended December 31, 2019 | 287 | | | 206 | | | 3 | | | 0 | | | 33 | | | 37 | | | 9 | | | 6 | | | 5 | |
In the fourth quarter of 2018, Exelon, Generation, BGE, PHI, Pepco, and DPL decreased their unrecognized state tax benefits by $241 million, $33 million, $120 million, $88 million, $66 million, and $22 million, respectively, due to the receipt of favorable guidance with respect to the deductibility of certain depreciable fixed assets. The recognition of these tax benefits decreased the effective tax rate at Exelon and Generation resulting in an income tax benefit of approximately $26 million. The recognition of the tax benefits related to BGE, PHI, Pepco, and DPL was offset by corresponding regulatory liabilities and that portion had no immediate impact to their effective tax rate.
Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation in 2012 and PHI in 2016. In the first quarter 2017, as a part of its examination of Exelon's return, the IRS National Office issued guidance concurring with Exelon's position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million and $22 million, respectively, in the first quarter of 2017 resulting in a benefit to Income taxes on Exelon's, Generation's, PHI's, Pepco's, DPL's, and ACE's Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.
Exelon reduced the liability related to the uncertain tax position associated with the like-kind exchange in the second quarter of 2017.
Unrecognized tax benefits that if recognized would affect the effective tax rate
Exelon, Generation, ComEd and PHI have $463 million, $408 million, $2 million and $31 million, respectively, of unrecognized tax benefits at December 31, 2018 that, if recognized, would decrease the effective tax rate. PHI has $21 million of unrecognized state tax benefits at December 31, 2018 that, if recognized, $14 million would be in the form of a net operating loss carryforward, which is expected to require a full valuation allowance based on present circumstances. PHI and ACE have $14 million of unrecognized tax benefits at December 31, 2018 that, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Exelon, Generation, ComEd and PHI had $523 million, $461 million, $2 million and $32 million, respectively, of unrecognized tax benefits at December 31, 2017 that, if recognized, would decrease the effective tax rate. BGE, PHI, Pepco, DPL, and ACE have $120 million, $94 million, $59 million, $21 million and $14 million of unrecognized tax benefits at December 31, 2017 that, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
Exelon, Generation, PHI, Pepco, DPL, | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Financing cash flows from finance leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2020 | | | | | | | | | | | $ | 6 | | | $ | 2 | | | $ | 3 | | | $ | 1 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
ROU assets obtained in exchange for operating and ACE had $633 million, $483 million, $93 million, $21 million, $16 million,finance lease obligations were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | $ | 1 | | | $ | 3 | | | $ | 0 | | | $ | 1 | | | $ | 0 | | | $ | (1) | | | $ | 0 | | | $ | (1) | | | $ | 0 | |
| For the year ended December 31, 2019 | 52 | | | 14 | | | 6 | | | 0 | | | 2 | | | (3) | | | (1) | | | (2) | | | (1) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | $ | 29 | | | $ | 8 | | | $ | 14 | | | $ | 7 | |
| | | | | | | | | | | | | | | | | |
Lessor
The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each registrant and $22 million, respectively,other terms and conditions of unrecognized tax benefits at December 31, 2016 that, if recognized, would decrease the effective tax rate. BGE, PHI, Pepco and DPL had $120 million, $80 million, $59 million, and $21 million of unrecognized tax benefits at December 31, 2016 that, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Unrecognized tax benefits that if recognized would affect only the timing of tax payments
There are no unrecognized tax benefitstheir lease agreements as of December 31, 2018 that affect only the timing of tax payments.2020.
Exelon and Generation had $7 million of unrecognized tax benefits at December 31, 2017 for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Contracted generation | ● | | ● | | | | | | | | | | | | | | |
| Real estate | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● |
| | | | | | | | | | | | | | | | | |
Exelon, Generation and ComEd had $83 million, $7 million and $(12) million of unrecognized tax benefits at December 31, 2016 for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in years) | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Remaining lease terms | 1-82 | | 1-31 | | 1-16 | | 1-82 | | 22 | | 1-12 | | 1-5 | | 11-12 | | 1 |
| Options to extend the term | 1-79 | | 1-5 | | 5-79 | | 5-50 | | N/A | | 5 | | N/A | | N/A | | N/A |
| | | | | | | | | | | | | | | | | |
The disallowancecomponents of such positions would not materially affect the annual effective tax rate but would accelerate the payment of cashlease income were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 52 | | | $ | 47 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 3 | | | $ | 0 | | | $ | 3 | | | $ | 0 | |
| Variable lease income | 283 | | | 282 | | | 0 | | | 0 | | | 0 | | | 1 | | | 0 | | | 1 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 54 | | | $ | 47 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 5 | | | $ | 0 | | | $ | 4 | | | $ | 0 | |
| Variable lease income | 261 | | | 258 | | | 0 | | | 0 | | | 0 | | | 3 | | | 0 | | | 3 | | | 0 | |
Future minimum lease payments to or defer the receipt of the cash tax benefit from, the taxing authority to an earlier or later period respectively.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
Like-Kind Exchange
Asbe recovered under operating leases as of December 31, 2018, Exelon and ComEd have approximately $33 million and $2 million, respectively,2020 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2021 | $ | 51 | | | $ | 45 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 4 | | | $ | 1 | | | $ | 3 | | | $ | 0 | |
| 2022 | 50 | | | 45 | | | 0 | | | 0 | | | 0 | | | 4 | | | 0 | | | 3 | | | 0 | |
| 2023 | 49 | | | 45 | | | 0 | | | 0 | | | 0 | | | 4 | | | 0 | | | 4 | | | 0 | |
| 2024 | 49 | | | 45 | | | 0 | | | 0 | | | 0 | | | 3 | | | 0 | | | 3 | | | 0 | |
| 2025 | 48 | | | 45 | | | 0 | | | 0 | | | 0 | | | 4 | | | 0 | | | 4 | | | 0 | |
| Remaining years | 217 | | | 182 | | | 1 | | | 4 | | | 1 | | | 31 | | | 0 | | | 31 | | | 0 | |
| Total | $ | 464 | | | $ | 407 | | | $ | 1 | | | $ | 4 | | | $ | 1 | | | $ | 50 | | | $ | 1 | | | $ | 48 | | | $ | — | |
Settlement of Income Tax Audits, Refund Claims, and Litigation
As of December 31, 2018, Exelon, Generation, PHI and ACE have approximately $425 million, $411 million, $14 million, and $14 million respectively, of unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, refund claims, and the outcomes of pending court cases. Of the above unrecognized tax benefits, Exelon and Generation have $411 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefit related to PHI and ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Total amounts of interest and penalties recognized
The following tables represent the net interest and penalties receivable (payable), including interest and penalties related to tax positions reflected in the Registrants’ Consolidated Balance Sheets.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net interest receivable (payable) as of | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| December 31, 2018 | $ | 236 |
| | $ | (2 | ) | | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| December 31, 2017 | 233 |
| | (3 | ) | | 4 |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net penalties payable as of | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| December 31, 2018 | $ | (17 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| December 31, 2017 | (17 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 12 — Asset Impairments
12. Asset Impairments (Exelon and Generation)
The following tables set forthRegistrants evaluate the net interestcarrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and penalty expense, including interestgeneration forecasts, projected capital and penalties related to tax positions, recognized in Interest expense, netmaintenance expenditures and Other, net in Other income and deductionsdiscount rates. A variation in the Registrants’assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.
Antelope Valley Solar Facility
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and 0 impairment charge was recorded.
The United States Bankruptcy Court entered an order on June 20, 2020 confirming PG&E’s plan of reorganization. On July 1, 2020 the plan became effective, and PG&E emerged from bankruptcy. Under the confirmed plan, PG&E will continue to honor the existing PPA agreement with Antelope Valley.
See Note 17 - Debt and Credit Agreements for additional information.
New England Asset Group
During the first quarter of 2018, Mystic Unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire its Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. These events suggested that the carrying value of the New England asset group may be impaired. In the first quarter of 2018, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and 0 impairment charge was required.
In the third quarter of 2020, in conjunction with the retirement announcement of Mystic Units 8 and 9, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the estimated undiscounted future cash flows and fair value of the New England asset group were less than their carrying values. As a result, a pre-tax impairment charge of $500 million was recorded in the third quarter of 2020 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. See Note 7 - Early Plant Retirements for additional information.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net interest expense (income) for the years ended | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
| December 31, 2018 | $ | (3 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| December 31, 2017 | 37 |
| | (1 | ) | | 11 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| December 31, 2016 | 165 |
| | (13 | ) | | 117 |
| | — |
| | — |
| | 6 |
| | — |
| | (1 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net penalty expense (income) for the years ended | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
| December 31, 2018 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| December 31, 2017 | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| December 31, 2016 | 106 |
| | — |
| | 86 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
|
| | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| PHI | December 31, 2018 | | December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Net interest expense | $ | — |
| | $ | — |
| | $ | (2 | ) | | | $ | — |
|
DescriptionIn the third quarter of tax years open to assessment by major jurisdiction
|
| |
Taxpayer | Open Years |
Exelon (and predecessors) and subsidiaries consolidated federal income tax returns | 1999, 2001-2017 |
PHI Holdings and subsidiaries consolidated federal income tax returns | 2013, 2015-2016 |
Exelon and subsidiaries Illinois unitary income tax returns | 2010-2017 |
Constellation combined New York corporate income tax returns | 2010-March 2012 |
Exelon combined New York corporate income tax returns
| 2011-2017 |
Exelon New Jersey corporate income tax returns | 2013-2017 |
Exelon Pennsylvania corporate net income tax returns | 2011-2017
|
PECO Pennsylvania separate company returns | 2015-2017
|
DPL Delaware separate company returns | Same as federal |
ACE New Jersey separate company returns | 2014-2017 |
Exelon and subsidiaries District of Columbia corporate income tax returns | 2015-2017 |
PHI Holdings and subsidiaries District of Columbia corporate income tax returns | 2015-2016
|
Various separate company Maryland corporate net income tax returns | Same as federal |
Other Tax Matters
Like-Kind Exchange
Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on2020, in conjunction with the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a portionretirement announcements of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisionsByron and Dresden nuclear plants, Generation completed a comprehensive review of the IRC. The like-kind exchange replacement property purchased by Exelon included interestsestimated undiscounted future cash flows of the Midwest asset group and 0 impairment charge was required.
Generation will continue to monitor the recoverability of the carrying value of the Midwest asset group as certain other nuclear plants in three municipal-ownedIllinois are also showing increased signs of economic distress, which could lead to an early retirement. See Note 7 - Early Plant Retirements for additional information.
Equity Method Investments in Certain Distributed Energy Companies
In the third quarter of 2019, Generation’s equity method investments in certain distributed energy companies were fully impaired due to an other-than-temporary decline in market conditions and underperforming projects.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 12 — Asset Impairments
electric generation facilities which were properly leased back to the municipalities. As previously disclosed, Exelon terminated its investment in one of the leases in 2014 and the remaining two leases were terminated in 2016.
The IRS asserted that the Exelon purchase and leaseback transaction was substantially similar to a leasing transaction, known as a SILO, which is a listed transaction that the IRS has identified as a potentially abusive tax shelter. Thus, they disagreed with Exelon's position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999. In 2013, the IRS issued a notice of deficiency to Exelon and Exelon filedGeneration recorded a petition to initiate litigation in the United States Tax Court. In 2016, the Tax Court held that Exelon was not entitled to defer gain on the transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for $90pre-tax impairment charge of $164 million in penaltiesEquity in losses of unconsolidated affiliates and interest on the penalties. Exelon has fully paid the amounts assessed resulting from the Tax Court decision.
In September 2017, Exelon appealed the Tax Court decisionan offsetting pre-tax $96 million in Net income attributable to the U.S. Courtnoncontrolling interests in their Consolidated Statements of Appeals for the Seventh Circuit. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the Tax Court’s decision. Exelon filed a petition seeking rehearing of the Seventh Circuit’s decision, but the Seventh Circuit denied that petition in December 2018. Exelon has until March 5, 2019 to seek a further review by the U.S. Supreme Court.
State Income Tax Law Changes
On April 24, 2018, Maryland enacted companion bills, House Bill 1794Operations and Senate Bill 1090, providing for a phase in of a single sales factor apportionment formula from the current three factor formula for determining an entity's Maryland state income taxes. The single sales factor will be fully phased in by 2022.
In the second quarter of 2018, Exelon, Generation, PHI, Pepco and DPL recorded a one-time increase to deferred income taxes of approximately $16 million, $5 million, $17 million, $16 million and $1 million, respectively. At PHI, Pepco and DPL, the increase to the Maryland deferred income tax liability was offset by regulatory assets. Further, the change in tax law is not expected to have a material ongoing impact to Exelon's, Generation's, PHI's, Pepco's or DPL's future results of operations.
Long-Term Marginal State Income Tax Rate (Exelon, Generation, PHI and Pepco)
In the third quarter of 2018, Exelon reviewed and updated its marginal state income tax rates based on 2017 state apportionment rates.Comprehensive Income. As a result, Generation accelerated the amortization of the rate changes, in the third quarter of 2018,investment tax credits associated with these companies and Exelon Generation, PHI and DPLGeneration recorded a one-timebenefit of $46 million in Income taxes. The impairment charge and the accelerated amortization of investment tax credits resulted in a net $15 million decrease to deferred income taxes of approximately $50 million, $53 million, $4 millionExelon’s and $2 million respectively. Pepco recorded a one-time increase to deferred income taxes of approximately $1 million. Exelon, PHI and DPL recorded a corresponding regulatory liability of approximately $1 million, $1 million and $2 million respectively. Pepco recorded a corresponding regulatory asset of approximately $1 million. Further, Exelon,Generation’s earnings. See Note 23 — Variable Interest Entities for additional information.
13. Intangible Assets (Exelon, Generation, and PHI recorded a decrease to income tax expense (net of federal taxes) of approximately $50 million, $53 million and $3 million.
Allocation of Tax Benefits (All Registrants)
Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE are all partyACE)
Goodwill
The following table presents the gross amount, accumulated impairment loss, and carrying amount of goodwill at Exelon, ComEd, and PHI as of December 31, 2020 and 2019. There were 0 additions or impairments during the years ended December 31, 2020 and 2019.
| | | | | | | | | | | | | | | | | |
| Gross Amount | | Accumulated Impairment Loss | | Carrying Amount |
| Exelon | $ | 8,660 | | | $ | 1,983 | | | $ | 6,677 | |
ComEd(a) | 4,608 | | | 1,983 | | | 2,625 | |
PHI(b) | 4,005 | | | 0 | | | 4,005 | |
__________
(a)Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).
(b)Reflects goodwill recorded in 2016 from the PHI merger.
Goodwill is not amortized, but is subject to an agreement with Exelonassessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each partyPHI's reporting units below their carrying amounts. A reporting unit is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treatedoperating segment or one level below an operating segment (known as a contribution tocomponent) and is the capitallevel at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the party receiving the benefit. During 2018, Generation, PECO, BGE, PHIcomponent constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd recorded an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement of $155 million, $48 million, $26 million, $2 million and $1 million respectively.has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE did not record an allocation of federal tax benefits from Exelon underACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the Tax Sharing Agreement as a result of a tax net operating loss.
During 2017, Generation, PECO, BGE, and PHI recorded an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement of $102 million, $16 million, $10 million and $7 million respectively. ComEd, Pepco, DPL, and ACE did not recordoperating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively.
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed. If an allocationentity bypasses the qualitative assessment, a quantitative, fair value-based assessment is performed, which compares the fair value of federal tax benefits from Exelon under the Tax Sharing Agreement asreporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the entity recognizes an impairment charge, which is limited to the amount of goodwill allocated to the reporting unit.
Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a resultweighted combination of a tax netdiscounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating loss.and capital cash flows for ComEd's, Pepco's, DPL's, and ACE's businesses, and the fair value of debt.
During 2016, Generation, PECO and BGE recorded an allocation
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Intangible Assets
DPL2020 and ACE2019 Goodwill Impairment Assessment. ComEd and PHI qualitatively determined that it was more likely than not that the fair values of their reporting units exceeded their carrying values and, therefore, did not record an allocationperform quantitative assessments as of federal tax benefits from ExelonNovember 1, 2020 and 2019 for ComEd and PHI. The last quantitative assessments performed were as they were not a partof November 1, 2016 for ComEd and November 1, 2018 for PHI.
While the annual assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, 2015 consolidated tax return.ComEd's, and PHI’s goodwill, which could be material.
Other Intangible Assets and Liabilities 15. Asset Retirement Obligations (All Registrants)
Nuclear Decommissioning Asset Retirement Obligations
Generation has a legal obligation to decommission its nuclear power plantsExelon’s, Generation’s, ComEd’s, and PHI's other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities and Other deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following the expirationas of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accountingDecember 31, 2020 and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which,2019. The intangible assets and liabilities shown below are amortized on a unit-by-unitstraight line basis, considers multiple outcome scenarios that include significant estimates and assumptions, andexcept for unamortized energy contracts which are based on decommissioning cost studies, cost escalation rates, probabilisticamortized in relation to the expected realization of the underlying cash flow models and discount rates. Generation updates its ARO annually unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.flows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2020 | | December 31, 2019 |
| | Gross | | Accumulated Amortization | | Net | | Gross | | Accumulated Amortization | | Net |
| Generation | | | | | | | | | | | | |
| Unamortized Energy Contracts | | $ | 1,963 | | | $ | (1,642) | | | $ | 321 | | | $ | 1,967 | | | $ | (1,612) | | | $ | 355 | |
| Customer Relationships | | 326 | | | (215) | | | 111 | | | 343 | | | (190) | | | 153 | |
| Trade Name | | 222 | | | (197) | | | 25 | | | 243 | | | (193) | | | 50 | |
| | | | | | | | | | | | |
| ComEd | | | | | | | | | | | | |
| Chicago Settlement Agreements | | 162 | | | (162) | | | 0 | | | 162 | | | (155) | | | 7 | |
| PHI | | | | | | | | | | | | |
| Unamortized Energy Contracts | | (1,515) | | | 1,188 | | | (327) | | | (1,515) | | | 1,073 | | | (442) | |
| Exelon Corporate | | | | | | | | | | | | |
| Software License | | 95 | | | (53) | | | 42 | | | 95 | | | (44) | | | 51 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Exelon | | $ | 1,253 | | | $ | (1,081) | | | $ | 172 | | | $ | 1,295 | | | $ | (1,121) | | | $ | 174 | |
The following table provides a rollforwardsummarizes the amortization expense related to intangible assets and liabilities for each of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2017 toyears ended December 31, 2020, 2019, and 2018:
|
| | | |
| Nuclear decommissioning ARO at January 1, 2017 | $ | 8,734 |
|
| Accretion expense | 458 |
|
| Acquisition of FitzPatrick | 444 |
|
| Net increase due to changes in, and timing of, estimated future cash flows | 34 |
|
| Costs incurred related to decommissioning plants | (8 | ) |
Nuclear decommissioning ARO at December 31, 2017 (a) | 9,662 |
|
| Accretion expense | 478 |
|
| Net decrease due to changes in, and timing of, estimated future cash flows | (77 | ) |
| Costs incurred related to decommissioning plants | (58 | ) |
Nuclear decommissioning ARO at December 31, 2018 (a) (b) | $ | 10,005 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | Exelon(a)(b) | | Generation(a) | | ComEd | | PHI(b) |
| 2020 | | $ | (17) | | | $ | 81 | | | $ | 7 | | | $ | (115) | |
| 2019 | | (28) | | | 74 | | | 7 | | | (119) | |
| 2018 | | (109) | | | 63 | | | 7 | | | (188) | |
__________
| |
(a) | Includes $22 million and $13 million as the current portion of the ARO at December 31, 2018 and 2017, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets. |
| |
(b) | Includes $772 million of ARO related to Oyster Creek which is classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018. See Note 5 — Mergers, Acquisitions and Dispositions for additional information. |
The net $77(a)At Exelon and Generation, amortization of unamortized energy contracts totaling $30 million, decrease$21 million, and $14 million for the years ended December 31, 2020, 2019, and 2018, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.
(b)At Exelon and PHI, amortization of the ARO during 2018 for changes in theunamortized energy contract fair value adjustment amounts and timingthe corresponding offsetting regulatory asset and liability amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments include a $203 million decrease primarily due to lower estimated costs for the construction of interim spent fuel storage at TMIOperations and a net decrease in estimated costs to decommission Calvert Cliffs, FitzPatrick, Limerick, and Salem nuclear units resulting from the completion of updated cost studies. These adjustments also include a decrease due to changes in decommissioning scenarios and their probabilities. These decreases were partially offset by a $116 million increase for the impact of the early retirement and the announced pending sale of Oyster Creek and a $122 million increase for estimated cost escalation rates, primarily for labor, energy and waste burial costs. See Note 5 — Mergers, Acquisitions and Dispositions and Note 8—Early Plant Retirements for additional information regarding Oyster Creek.Comprehensive Income.
The net $34 million increase in the ARO during 2017 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments include a $178 million increase due to higher assumed probabilities of early retirement of Salem and a $138 million increase in TMI’s ARO liability associated with the May 30, 2017 announcement to early retire the unit on September 30, 2019. The increase in TMI's ARO liability incorporates the early shutdown date, increases in the probabilities of longer term decommissioning scenarios, and an increase infollowing table summarizes the estimated costsfuture amortization expense related to decommission based on an updated decommissioning cost study. See Note 8—Early Plant Retirements forintangible assets and liabilities as of December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ending December 31, | | Exelon | | Generation | | | | PHI |
| 2021 | | $ | (1) | | | $ | 81 | | | | | $ | (92) | |
| 2022 | | (22) | | | 57 | | | | | (89) | |
| 2023 | | (20) | | | 51 | | | | | (81) | |
| 2024 | | 20 | | | 48 | | | | | (38) | |
| 2025 | | 40 | | | 41 | | | | | (5) | |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Intangible Assets
additional information regarding SalemRenewable Energy Credits (Exelon and TMI. These increasesGeneration)
Exelon’s and Generation’s RECs are included in Other current assets and Other deferred debits and other assets in the ARO were partially offset byConsolidated Balance Sheets. Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a $180 million decreasestand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Generally, revenue for refinementsRECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in estimated fleet wide labor costs expected to be incurred for certain on-site personnel during decommissioning as well as net decreases resulting from updatestime when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the cost studiescustomer.
The following table presents the current and noncurrent RECs as of Clinton, Quad CitiesDecember 31, 2020 and Dresden.2019:
| | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2020 | | As of December 31, 2019 |
| Exelon | | Generation | | Exelon | | Generation |
| Current REC's | $ | 632 | | | $ | 621 | | | $ | 345 | | | $ | 336 | |
| Noncurrent REC's | 0 | | | 0 | | | 86 | | | 86 | |
14. Income Taxes (All Registrants)
NDT Funds
NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.
The NDT funds associated with Generation's nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected.collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a decrease from the previously approved annual collection of approximately $24 million primarily due to the removal of the collections for Limerick Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the new rates became effective January 1, 2018.
Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party (see Zion Station Decommissioning below) and the CENG units, where any shortfall is required to be funded by both Generation and EDF. Generation, through PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from utility customers for any of Generation's other nuclear units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to NDT funds that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management and decommissioning) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities.
At December 31, 20182020 and 2017,2019, Exelon and Generation had NDT funds totaling $12,695$14,599 millionand $13,349$13,353 million, respectively. Included within the December 31, 2018 balance is the $890 million reclassification of Oyster Creek NDT as Assets held for sale in Exelon's and Generation's Consolidated Balance Sheets. See Note 5 — Mergers, Acquisitions and Dispositions for additional information regarding the announced pending sale of Oyster Creek. The NDT funds include $144$134 million and $77$163 million for the current portion of the NDT at December 31, 20182020 and 2017,2019, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Balance Sheets. See Note 11—Fair Value of24 — Supplemental Financial Assets and LiabilitiesInformation for additional information related toon activities of the NDT funds.
The following table provides unrealized (losses) gains on NDT funds of Exelon and Generation for the years ended 2018, 2017 and 2016:
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
Net unrealized (losses) gains on NDT funds—Regulatory Agreement Units (a) | $ | (715 | ) | | $ | 455 |
| | $ | 216 |
|
Net unrealized (losses) gains on NDT funds—Non-Regulatory Agreement Units (b) | (483 | ) | | 521 |
| | 194 |
|
__________
| |
(a) | Net unrealized (losses) gains related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities in Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates in Generation’s Consolidated Balance Sheets. |
| |
(b) | Net unrealized (losses) gains related to Generation’s NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. |
Realized earnings, including interest and dividends on the NDT funds, for the non-Regulatory Agreement Units investments are recognized when earned and are included in Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income whereas the Regulatory Agreement Units are eliminated within Other, net.
Accounting Implications of the Regulatory Agreements with ComEd and PECO
Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.Income and are recorded by Generation and the corresponding regulated utility as a component of the intercompany and regulatory balances on the balance sheet. For the former ComEd units, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statementspurposes of Operations and Comprehensive Incomemaking this determination, the decommissioning obligation referred to is different, as long asdescribed below, from the NDT funds are expected to exceedcalculation used in the total estimated decommissioning obligation. NRC minimum funding obligation filings based on NRC guidelines.
For the former PECO units, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from PECO customers in the event of a shortfall and the obligation for Generation to ultimately return any excess funds to PECO customers (on an aggregate basis for all seven units),decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables or noncurrent receivables to affiliates at Generation. ComEd andGeneration with PECO have recordedrecording an equal noncurrent affiliate receivable from or payable to Generation and a corresponding regulatory liability.
Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon’s and Generation’s financial statements could be material. As of December 31, 2018, the NDT funds of each of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are expected to exceed the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.
liability or regulatory asset. Any changes to the existing PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s financial statements could be material.
For the former ComEd units, given no further recovery from ComEd customers is permitted and Generation retains an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, the offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results with Generation recognizing an intercompany payable to ComEd while ComEd records an intercompany receivable from Generation with a corresponding regulatory liability.However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible and accounting for decommissioning-related activities at Generation for that unit would not be offset, and the impact to Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income could be material during such periods.
As of December 31, 2020, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are currently offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
See Note 4—3 — Regulatory Matters and Note 25—25 — Related Party Transactions for additional information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd, and PECO
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.
Zion Station Decommissioning
In 2010, Generation completed an Asset Sale Agreement (ASA)ASA under which ZionSolutions assumed responsibility for decommissioning Zion Station and Generation transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds. Pursuant to the ASA, ZionSolutions will periodically request reimbursement, subject to certain restrictions, from the Zion Station-related NDT funds for costs incurred related to its decommissioning efforts at Zion Station. As the transfer of the Zion Station assets did not qualify for asset sale accounting treatment, the related NDT funds were reclassified as pledged assets for Zion Station decommissioning, which are recorded within Other current assets within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction, and the transferred ARO for decommissioning was replaced with a payable for Zion Station decommissioning, which is recorded in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT fund assets, net of applicable taxes, are recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station.
Generation has retained its obligation for the SNF. Following ZionSolutions' completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility.
Generation has a liability of $120 million, which is included withinhad retained its obligation for the nuclear decommissioning ARO at December 31, 2018. Generation also has retainedSNF as well as certain NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion StationAs of December 31, 2020, the ARO associated with Zion's SNF storage facility is $175 million and the NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders.
The following table provides Exelon's and Generation's pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2018 and 2017:
|
| | | | | | | |
| | 2018 | | 2017 |
| Carrying value of Zion Station pledged assets | $ | 9 |
| | $ | 39 |
|
Current payable to ZionSolutions (a) | 9 |
| | 37 |
|
Cumulative withdrawals by ZionSolutions to pay decommissioning costs (b) | 965 | | 942 |
_______
| |
(a) | Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized gains and losses associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized. |
| |
(b) | Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings. |
ZionSolutions leased the land associated with Zion Station from Generation pursuant to a Lease Agreement. Under the Lease Agreement, ZionSolutions has committed to complete the required decommissioning work according to an established schedule and constructed a dry cask storage facility on the land and has loaded the SNF from the SNF pools onto the dry cask storage facility at Zion Station. Rent payable under the Lease Agreement is $1.00 per year, although the Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delays in the progress of decommissioning work at Zion Station or the construction of the dry cask SNF storage facility. To reduce the risk of default by ZionSolutions, EnergySolutions provided a $200 million letter of credit to be usedavailable to fund decommissioning costs in the event the NDT assetsthis obligation are insufficient. In accordance with the terms of the ASA, the letter of credit was reduced to $45 millionin May 2018 due to the completion of key decommissioning milestones. EnergySolutions and its parent company have also provided a performance guarantee and EnergySolutions has entered into other agreements that will provide rights and remedies for Generation and the NRC in the case of other specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
$66 million.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the NRC methodology differ from the ARO recorded in Generation’s and Exelon’s Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees.
Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 20182020 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals and with an assumed end-of-operations date of 2019 for TMI)renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).
In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 20182020 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-level radioactive waste)LLRW); (3) the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5%4% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.0%5.6% to 6.2%6.1% (as compared to a historical 5-year annual average pre-tax return of approximately 4.9%9.0%).
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial positions may be significantly adversely affected.
Generation filed its biennial decommissioning funding status report with the NRC on March 30, 2017April 1, 2019 for all units, including its shutdown units, except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, (see Zion Station Decommissioning above) and FitzPatrick which is still owned by Entergy as of the NRC reporting period. ThisLLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the April 1, 2019 submittal. On March 31, 2020, Generation filed its annual decommissioning funding status report with the NRC for Generation’s shutdown units (excluding Zion Station for the reason noted above). The annual status report demonstrated adequate decommissioning funding assurance as of December 31, 2019, for all of its shutdown reactors except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, in addition to collections from PECO ratepayers. See NDT Funds section above for additional information.
On March 28, 2018, Generation submitted its annual decommissioning funding status reportratepayers, and the ability to adjust those collections in accordance with the NRC for shutdown reactors, reactors within five years of shutdown except for Zion Station which is includedapproved PAPUC tariff. No additional actions are required aside from the PAPUC filing in a separate report toaccordance with the NRC submitted by EnergySolutions (see Zion Station Decommissioning above), and reactor involved in an acquisition. This report reflected the status of decommissioning funding assurance as of December 31, 2017 and included an update for the acquisition of FitzPatrick on March 31, 2017, the early retirement of TMI announced on May 30, 2017, an adjustment for the February 2, 2018 announced retirement date of Oyster Creek and the updated status of Peach Bottom Unit 1 based on the new collections rate described above. As of December 31, 2017, Generation provided adequate decommissioning funding assurance for all of its shutdown reactors, reactors within five years of shutdown, and reactor involved in an acquisition.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
tariff.
Generation will file its next decommissioning funding status report for all units with the NRC by March 31, 2019.2021. This report will reflect the status of decommissioning funding assurance as of December 31, 2018.2020 and will include the 2021 early retirements of Byron and Dresden. A shortfall at any unit could necessitate that Generation address the shortfall by, among other things, obtaining arequire Exelon to post parental guarantee for Generation'sGeneration’s share of the funding assurance. However, the amount of any required guarantee or other assurance will ultimately depend on the decommissioning approach adopted at Byron and Dresden, the associated level of costs, and the decommissioning trust fund investment performance going forward.
As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.
Non-Nuclear Asset Retirement Obligations (All Registrants)
Generation has AROs for plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations and other decommissioning-related activities. The Utility Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1—1 — Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
The following table provides a rollforward of the non-nuclear AROs reflected in the Registrants’ Consolidated Balance Sheets from January 1, 20172019 to December 31, 2018:2020:
| | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
Non-nuclear AROs at January 1, 2017 | $ | 393 |
| | $ | 199 |
|
| $ | 121 |
|
| $ | 28 |
|
| $ | 24 |
| | $ | 14 |
| | $ | 2 |
| | $ | 9 |
| | $ | 3 |
| |
| Net (decrease) increase due to changes in, and timing of, estimated future cash flows | (11 | ) | | (1 | ) |
| (13 | ) |
| (1 | ) |
| 2 |
| | 2 |
| | 1 |
| | 1 |
| | — |
| |
| Non-nuclear AROs at January 1, 2019 | | Non-nuclear AROs at January 1, 2019 | $ | 471 | | | $ | 238 | | | $ | 121 | | | $ | 28 | | | $ | 25 | | | $ | 52 | | | $ | 37 | | | $ | 11 | | | $ | 4 | |
| Net increase (decrease) due to changes in, and timing of, estimated future cash flows | | Net increase (decrease) due to changes in, and timing of, estimated future cash flows | 17 | | | 7 | | | 8 | | | 0 | | | (2) | | | 4 | | | 3 | | | 1 | | | 0 | |
| Development projects | 1 |
| | 1 |
|
| — |
|
| — |
|
| — |
| | — |
| | — |
| | — |
| | — |
| Development projects | 2 | | | 2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Accretion expense(a) | 18 |
| | 10 |
| | 7 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
| Deconsolidation of EGTP | (7 | ) | | (7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
| Payments | (10 | ) | | (5 | ) |
| (2 | ) |
| (1 | ) |
| (2 | ) | | — |
| | — |
| | — |
| | — |
| |
| Non-nuclear AROs at December 31, 2017 | 384 |
| | 197 |
|
| 113 |
|
| 27 |
|
| 24 |
| | 16 |
| | 3 |
|
| 10 |
|
| 3 |
| |
Net increase due to changes in, and timing of, estimated future cash flows(b) | 80 |
| | 35 |
|
| 7 |
|
| — |
|
| 2 |
| | 36 |
| | 34 |
| | 1 |
| | 1 |
| |
Accretion expense(a) | 16 |
| | 10 |
|
| 4 |
|
| 1 |
|
| 1 |
| | — |
| | — |
| | — |
| | — |
| Accretion expense(a) | 16 | | | 12 | | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | | 0 | | | 0 | |
| Asset divestitures | (3 | ) | | (3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Asset divestitures | (42) | | | (42) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Payments | (6 | ) | | (1 | ) |
| (3 | ) |
| — |
|
| (2 | ) | | — |
| | — |
| | — |
| | — |
| Payments | (4) | | | (1) | | | (1) | | | (1) | | | (1) | | | 0 | | | 0 | | | 0 | | | 0 | |
| Non-nuclear AROs at December 31, 2018 | $ | 471 |
| | $ | 238 |
|
| $ | 121 |
|
| $ | 28 |
|
| $ | 25 |
| | $ | 52 |
| | $ | 37 |
|
| $ | 11 |
|
| $ | 4 |
| |
| Non-nuclear AROs at December 31, 2019 | | Non-nuclear AROs at December 31, 2019 | 460 | | | 216 | | | 129 | | | 28 | | | 23 | | | 57 | | | 41 | | | 12 | | | 4 | |
| Net increase (decrease) due to changes in, and timing of, estimated future cash flows | | Net increase (decrease) due to changes in, and timing of, estimated future cash flows | 7 | | | 2 | | | 0 | | | 2 | | | 1 | | | 1 | | | (3) | | | 2 | | | 2 | |
| Development projects | | Development projects | 1 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Accretion expense(a) | | Accretion expense(a) | 16 | | | 11 | | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | | 0 | | | 0 | |
| Asset divestitures | | Asset divestitures | (4) | | | (4) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Payments | | Payments | (9) | | | (4) | | | (1) | | | (2) | | | (2) | | | 0 | | | 0 | | | 0 | | | 0 | |
AROs reclassified to liabilities held for sale(b) | | AROs reclassified to liabilities held for sale(b) | (10) | | | (10) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Non-nuclear AROs at December 31, 2020 | | Non-nuclear AROs at December 31, 2020 | $ | 461 | | | $ | 212 | | | $ | 129 | | | $ | 29 | | | $ | 23 | | | $ | 59 | | | $ | 39 | | | $ | 14 | | | $ | 6 | |
__________
(a)For ComEd, PECO, BGE, PHI, Pepco, and DPL, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
(b)Represents AROs related to Generation's solar business, which were classified as held for sale as a result of the sale agreement. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.
11. Leases(All Registrants)
Lessee
The Registrants have operating and finance leases for which they are the lessees. The following tables outline the significant types of leases at each registrant and other terms and conditions of the lease agreements as of December 31, 2020. Exelon, Generation, ComEd, PECO, and BGE did not have material finance leases in 2020 or in 2019. PHI, Pepco, DPL, and ACE also did not have material finance leases in 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(a) | For Exelon | | Generation | | ComEd and | | PECO the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment. | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Contracted generation | ● | | ● | | | | | | | | | | | | | | |
(b)Real estate | In 2018, Pepco recorded an increase of $22 million in Operating● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● |
Vehicles and maintenance expense primarily related to asbestos identified at its Buzzard Point property as part of an annual ARO study. Buzzard Point is a waterfront propertyequipment | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in years) | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Remaining lease terms | 1-85 | | 1-35 | | 1-4 | | 1-13 | | 1-85 | | 1-11 | | 1-11 | | 1-11 | | 1-7 |
| Options to extend the term | 2-30 | | 2-30 | | 5 | | N/A | | N/A | | 3-30 | | 5 | | 3-30 | | 5 |
| Options to terminate within | 1-12 | | 1-4 | | 2 | | N/A | | 1 | | N/A | | N/A | | N/A | | N/A |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
The components of operating lease costs were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | |
| Operating lease costs | $ | 292 | | | $ | 194 | | | $ | 3 | | | $ | 1 | | | $ | 33 | | | $ | 46 | | | $ | 11 | | | $ | 13 | | | $ | 6 | |
| Variable lease costs | 241 | | | 234 | | | 1 | | | 0 | | | 1 | | | 2 | | | 1 | | | 1 | | | 0 | |
| Short-term lease costs | 2 | | | 2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Total lease costs (a) | $ | 535 | | | $ | 430 | | | $ | 4 | | | $ | 1 | | | $ | 34 | | | $ | 48 | | | $ | 12 | | | $ | 14 | | | $ | 6 | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | |
| Operating lease costs | $ | 320 | | | $ | 222 | | | $ | 3 | | | $ | 1 | | | $ | 33 | | | $ | 48 | | | $ | 12 | | | $ | 14 | | | $ | 7 | |
| Variable lease costs | 300 | | | 282 | | | 2 | | | 0 | | | 2 | | | 6 | | | 2 | | | 2 | | | 1 | |
| Short-term lease costs | 19 | | | 19 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Total lease costs (a) | $ | 639 | | | $ | 523 | | | $ | 5 | | | $ | 1 | | | $ | 35 | | | $ | 54 | | | $ | 14 | | | $ | 16 | | | $ | 8 | |
__________
(a)Excludes $48 million, $44 million, $4 million, and $4 million of sublease income recorded at Exelon, Generation, PHI, and DPL, respectively, for the year ended December 31, 2020 and $51 million, $44 million, $7 million, and $7 million of sublease income recorded at Exelon, Generation, PHI, and DPL, respectively, for the year ended December 31, 2019.
PHI, Pepco, DPL, and ACE recorded finance lease costs of $9 million, $3 million, $4 million, and $2 million, respectively, for the year ended December 31, 2020.
The following table presents the Registrants' rental expense under the prior lease accounting guidance for the year ended December 31, 2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rent expense | $ | 670 | | | $ | 558 | | | $ | 7 | | | $ | 10 | | | $ | 35 | | | $ | 48 | | | $ | 10 | | | $ | 13 | | | $ | 8 | |
| | | | | | | | | | | | | | | | | |
__________
(a)Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments table. Payments made under Generation's contracted generation lease agreements totaled $493 million.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
The following tables provide additional information regarding the presentation of operating and finance lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance Sheets:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Exelon(a) | | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | | | | | | | | | | | | | | | | | |
| Operating lease ROU assets | | | | | | | | | | | | | | | | | |
| Other deferred debits and other assets | $ | 1,064 | | | $ | 726 | | | $ | 7 | | | $ | 1 | | | $ | 46 | | | $ | 241 | | | $ | 49 | | | $ | 54 | | | $ | 15 | |
| | | | | | | | | | | | | | | | | |
| Operating lease liabilities | | | | | | | | | | | | | | | | | |
| Other current liabilities | 213 | | | 132 | | | 3 | | | 0 | | | 45 | | | 31 | | | 6 | | | 9 | | | 4 | |
| Other deferred credits and other liabilities | 1,089 | | | 775 | | | 5 | | | 1 | | | 19 | | | 224 | | | 46 | | | 56 | | | 11 | |
| Total operating lease liabilities | $ | 1,302 | | | $ | 907 | | | $ | 8 | | | $ | 1 | | | $ | 64 | | | $ | 255 | | | $ | 52 | | | $ | 65 | | | $ | 15 | |
| | | | | | | | | | | | | | | | | |
| As of December 31, 2019 | | | | | | | | | | | | | | | | | |
| Operating lease ROU assets | | | | | | | | | | | | | | | | | |
| Other deferred debits and other assets | $ | 1,305 | | | $ | 895 | | | $ | 9 | | | $ | 2 | | | $ | 77 | | | $ | 273 | | | $ | 56 | | | $ | 63 | | | $ | 18 | |
| | | | | | | | | | | | | | | | | |
| Operating lease liabilities | | | | | | | | | | | | | | | | | |
| Other current liabilities | 225 | | | 157 | | | 3 | | | 0 | | | 32 | | | 31 | | | 6 | | | 9 | | | 4 | |
| Other deferred credits and other liabilities | 1,307 | | | 925 | | | 8 | | | 1 | | | 50 | | | 254 | | | 51 | | | 65 | | | 14 | |
| Total operating lease liabilities | $ | 1,532 | | | $ | 1,082 | | | $ | 11 | | | $ | 1 | | | $ | 82 | | | $ | 285 | | | $ | 57 | | | $ | 74 | | | $ | 18 | |
__________
(a)Exelon's and Generation's operating ROU assets and lease liabilities include $387 million and $528 million, respectively, related to contracted generation as of December 31, 2020, and $515 million and $664 million, respectively, as of December 31, 2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | | | | | | | | | | | | | | | | | |
| Finance lease ROU assets | | | | | | | | | | | | | | | | | |
| Plant, property and equipment, net | | | | | | | | | | | $ | 50 | | | $ | 17 | | | $ | 20 | | | $ | 13 | |
| | | | | | | | | | | | | | | | | |
| Finance lease liabilities | | | | | | | | | | | | | | | | | |
| Long-term debt due within one year | | | | | | | | | | | 7 | | | 2 | | | 3 | | | 2 | |
| Long-term debt | | | | | | | | | | | 43 | | | 15 | | | 17 | | | 11 | |
| Total finance lease liabilities | | | | | | | | | | | $ | 50 | | | $ | 17 | | | $ | 20 | | | $ | 13 | |
The weighted average remaining lease terms, in years, for operating and finance leases were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | 10.1 | | 10.5 | | 3.8 | | 4.2 | | 8.3 | | 8.2 | | 9.1 | | 9.1 | | 4.0 |
| As of December 31, 2019 | 10.1 | | 10.6 | | 4.6 | | 4.4 | | 5.4 | | 9.0 | | 9.8 | | 9.7 | | 4.7 |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | | | | | | | | | | | 6.5 | | 6.3 | | 6.5 | | 6.5 |
| | | | | | | | | | | | | | | | | |
The weighted average discount rates for operating and finance leases were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | 4.7 | % | | 4.9 | % | | 3.0 | % | | 2.9 | % | | 3.8 | % | | 4.2 | % | | 4.0 | % | | 4.0 | % | | 3.5 | % |
| As of December 31, 2019 | 4.6 | % | | 4.8 | % | | 3.0 | % | | 3.2 | % | | 3.6 | % | | 4.2 | % | | 4.0 | % | | 4.0 | % | | 3.6 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| As of December 31, 2020 | | | | | | | | | | | 2.5 | % | | 2.6 | % | | 2.4 | % | | 2.4 | % |
| | | | | | | | | | | | | | | | | |
Future minimum lease payments for operating and finance leases as of December 31, 2020 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2021 | $ | 239 | | | $ | 145 | | | $ | 3 | | | $ | 1 | | | $ | 46 | | | $ | 40 | | | $ | 8 | | | $ | 11 | | | $ | 5 | |
| 2022 | 177 | | | 113 | | | 2 | | | 0 | | | 16 | | | 39 | | | 8 | | | 10 | | | 4 | |
| 2023 | 146 | | | 100 | | | 1 | | | 0 | | | 1 | | | 38 | | | 7 | | | 9 | | | 3 | |
| 2024 | 141 | | | 98 | | | 1 | | | 0 | | | 0 | | | 36 | | | 6 | | | 8 | | | 2 | |
| 2025 | 140 | | | 99 | | | 1 | | | 0 | | | 0 | | | 33 | | | 6 | | | 7 | | | 2 | |
| Remaining years | 834 | | | 640 | | | 0 | | | 0 | | | 18 | | | 120 | | | 28 | | | 35 | | | 0 | |
| Total | 1,677 | | | 1,195 | | | 8 | | | 1 | | | 81 | | | 306 | | | 63 | | | 80 | | | 16 | |
| Interest | 375 | | | 288 | | | 0 | | | 0 | | | 17 | | | 51 | | | 11 | | | 15 | | | 1 | |
| Total operating lease liabilities | $ | 1,302 | | | $ | 907 | | | $ | 8 | | | $ | 1 | | | $ | 64 | | | $ | 255 | | | $ | 52 | | | $ | 65 | | | $ | 15 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| Year | | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| 2021 | | | | | | | | | | | $ | 8 | | | $ | 3 | | | $ | 3 | | | $ | 2 | |
| 2022 | | | | | | | | | | | 8 | | | 3 | | | 3 | | | 2 | |
| 2023 | | | | | | | | | | | 8 | | | 3 | | | 3 | | | 2 | |
| 2024 | | | | | | | | | | | 8 | | | 3 | | | 3 | | | 2 | |
| 2025 | | | | | | | | | | | 8 | | | 3 | | | 3 | | | 2 | |
| Remaining years | | | | | | | | | | | 13 | | | 3 | | | 6 | | | 4 | |
| Total | | | | | | | | | | | 53 | | | 18 | | | 21 | | | 14 | |
| Interest | | | | | | | | | | | 3 | | | 1 | | | 1 | | | 1 | |
| Total finance lease liabilities | | | | | | | | | | | $ | 50 | | | $ | 17 | | | $ | 20 | | | $ | 13 | |
Cash paid for amounts included in the measurement of operating and finance lease liabilities were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating cash flows from operating leases |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | $ | 271 | | | $ | 204 | | | $ | 3 | | | $ | 1 | | | $ | 20 | | | $ | 39 | | | $ | 8 | | | $ | 9 | | | $ | 4 | |
| For the year ended December 31, 2019 | 287 | | | 206 | | | 3 | | | 0 | | | 33 | | | 37 | | | 9 | | | 6 | | | 5 | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Financing cash flows from finance leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2020 | | | | | | | | | | | $ | 6 | | | $ | 2 | | | $ | 3 | | | $ | 1 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
ROU assets obtained in exchange for operating and finance lease obligations were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | $ | 1 | | | $ | 3 | | | $ | 0 | | | $ | 1 | | | $ | 0 | | | $ | (1) | | | $ | 0 | | | $ | (1) | | | $ | 0 | |
| For the year ended December 31, 2019 | 52 | | | 14 | | | 6 | | | 0 | | | 2 | | | (3) | | | (1) | | | (2) | | | (1) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Finance Leases |
| | | | | | | | | | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | $ | 29 | | | $ | 8 | | | $ | 14 | | | $ | 7 | |
| | | | | | | | | | | | | | | | | |
Lessor
The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each registrant and other terms and conditions of their lease agreements as of December 31, 2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Contracted generation | ● | | ● | | | | | | | | | | | | | | |
| Real estate | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● | | ● |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in years) | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Remaining lease terms | 1-82 | | 1-31 | | 1-16 | | 1-82 | | 22 | | 1-12 | | 1-5 | | 11-12 | | 1 |
| Options to extend the term | 1-79 | | 1-5 | | 5-79 | | 5-50 | | N/A | | 5 | | N/A | | N/A | | N/A |
| | | | | | | | | | | | | | | | | |
The components of lease income were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 52 | | | $ | 47 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 3 | | | $ | 0 | | | $ | 3 | | | $ | 0 | |
| Variable lease income | 283 | | | 282 | | | 0 | | | 0 | | | 0 | | | 1 | | | 0 | | | 1 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 54 | | | $ | 47 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 5 | | | $ | 0 | | | $ | 4 | | | $ | 0 | |
| Variable lease income | 261 | | | 258 | | | 0 | | | 0 | | | 0 | | | 3 | | | 0 | | | 3 | | | 0 | |
Future minimum lease payments to be recovered under operating leases as of December 31, 2020 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2021 | $ | 51 | | | $ | 45 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 4 | | | $ | 1 | | | $ | 3 | | | $ | 0 | |
| 2022 | 50 | | | 45 | | | 0 | | | 0 | | | 0 | | | 4 | | | 0 | | | 3 | | | 0 | |
| 2023 | 49 | | | 45 | | | 0 | | | 0 | | | 0 | | | 4 | | | 0 | | | 4 | | | 0 | |
| 2024 | 49 | | | 45 | | | 0 | | | 0 | | | 0 | | | 3 | | | 0 | | | 3 | | | 0 | |
| 2025 | 48 | | | 45 | | | 0 | | | 0 | | | 0 | | | 4 | | | 0 | | | 4 | | | 0 | |
| Remaining years | 217 | | | 182 | | | 1 | | | 4 | | | 1 | | | 31 | | | 0 | | | 31 | | | 0 | |
| Total | $ | 464 | | | $ | 407 | | | $ | 1 | | | $ | 4 | | | $ | 1 | | | $ | 50 | | | $ | 1 | | | $ | 48 | | | $ | — | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 12 — Asset Impairments
12. Asset Impairments (Exelon and Generation)
The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.
Antelope Valley Solar Facility
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and 0 impairment charge was recorded.
The United States Bankruptcy Court entered an order on June 20, 2020 confirming PG&E’s plan of reorganization. On July 1, 2020 the plan became effective, and PG&E emerged from bankruptcy. Under the confirmed plan, PG&E will continue to honor the existing PPA agreement with Antelope Valley.
See Note 17 - Debt and Credit Agreements for additional information.
New England Asset Group
During the first quarter of 2018, Mystic Unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire its Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. These events suggested that the carrying value of the New England asset group may be impaired. In the first quarter of 2018, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and 0 impairment charge was required.
In the third quarter of 2020, in conjunction with the retirement announcement of Mystic Units 8 and 9, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the estimated undiscounted future cash flows and fair value of the New England asset group were less than their carrying values. As a result, a pre-tax impairment charge of $500 million was recorded in the third quarter of 2020 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. See Note 7 - Early Plant Retirements for additional information.
Midwest Asset Group
In the third quarter of 2020, in conjunction with the retirement announcements of the Byron and Dresden nuclear plants, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the Midwest asset group and 0 impairment charge was required.
Generation will continue to monitor the recoverability of the carrying value of the Midwest asset group as certain other nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement. See Note 7 - Early Plant Retirements for additional information.
Equity Method Investments in Certain Distributed Energy Companies
In the third quarter of 2019, Generation’s equity method investments in certain distributed energy companies were fully impaired due to an other-than-temporary decline in market conditions and underperforming projects.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 12 — Asset Impairments
Exelon and Generation recorded a pre-tax impairment charge of $164 million in Equity in losses of unconsolidated affiliates and an offsetting pre-tax $96 million in Net income attributable to noncontrolling interests in their Consolidated Statements of Operations and Comprehensive Income. As a result, Generation accelerated the amortization of investment tax credits associated with these companies and Exelon and Generation recorded a benefit of $46 million in Income taxes. The impairment charge and the accelerated amortization of investment tax credits resulted in a net $15 million decrease to Exelon’s and Generation’s earnings. See Note 23 — Variable Interest Entities for additional information.
13. Intangible Assets (Exelon, Generation, ComEd, PHI, Pepco, DPL, and ACE)
Goodwill
The following table presents the gross amount, accumulated impairment loss, and carrying amount of goodwill at Exelon, ComEd, and PHI as of December 31, 2020 and 2019. There were 0 additions or impairments during the years ended December 31, 2020 and 2019.
| | | | | | | | | | | | | | | | | |
| Gross Amount | | Accumulated Impairment Loss | | Carrying Amount |
| Exelon | $ | 8,660 | | | $ | 1,983 | | | $ | 6,677 | |
ComEd(a) | 4,608 | | | 1,983 | | | 2,625 | |
PHI(b) | 4,005 | | | 0 | | | 4,005 | |
__________
(a)Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).
(b)Reflects goodwill recorded in 2016 from the PHI merger.
Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively.
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed. If an entity bypasses the qualitative assessment, a quantitative, fair value-based assessment is performed, which compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the entity recognizes an impairment charge, which is limited to the amount of goodwill allocated to the reporting unit.
Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd's, Pepco's, DPL's, and ACE's businesses, and the fair value of debt.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Intangible Assets
2020 and 2019 Goodwill Impairment Assessment. ComEd and PHI qualitatively determined that it was more likely than not that the fair values of their reporting units exceeded their carrying values and, therefore, did not perform quantitative assessments as of November 1, 2020 and 2019 for ComEd and PHI. The last quantitative assessments performed were as of November 1, 2016 for ComEd and November 1, 2018 for PHI.
While the annual assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's, and PHI’s goodwill, which could be material.
Other Intangible Assets and Liabilities
Exelon’s, Generation’s, ComEd’s, and PHI's other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities and Other deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2020 and 2019. The intangible assets and liabilities shown below are amortized on a straight line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2020 | | December 31, 2019 |
| | Gross | | Accumulated Amortization | | Net | | Gross | | Accumulated Amortization | | Net |
| Generation | | | | | | | | | | | | |
| Unamortized Energy Contracts | | $ | 1,963 | | | $ | (1,642) | | | $ | 321 | | | $ | 1,967 | | | $ | (1,612) | | | $ | 355 | |
| Customer Relationships | | 326 | | | (215) | | | 111 | | | 343 | | | (190) | | | 153 | |
| Trade Name | | 222 | | | (197) | | | 25 | | | 243 | | | (193) | | | 50 | |
| | | | | | | | | | | | |
| ComEd | | | | | | | | | | | | |
| Chicago Settlement Agreements | | 162 | | | (162) | | | 0 | | | 162 | | | (155) | | | 7 | |
| PHI | | | | | | | | | | | | |
| Unamortized Energy Contracts | | (1,515) | | | 1,188 | | | (327) | | | (1,515) | | | 1,073 | | | (442) | |
| Exelon Corporate | | | | | | | | | | | | |
| Software License | | 95 | | | (53) | | | 42 | | | 95 | | | (44) | | | 51 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Exelon | | $ | 1,253 | | | $ | (1,081) | | | $ | 172 | | | $ | 1,295 | | | $ | (1,121) | | | $ | 174 | |
The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2020, 2019, and 2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | Exelon(a)(b) | | Generation(a) | | ComEd | | PHI(b) |
| 2020 | | $ | (17) | | | $ | 81 | | | $ | 7 | | | $ | (115) | |
| 2019 | | (28) | | | 74 | | | 7 | | | (119) | |
| 2018 | | (109) | | | 63 | | | 7 | | | (188) | |
__________
(a)At Exelon and Generation, amortization of unamortized energy contracts totaling $30 million, $21 million, and $14 million for the years ended December 31, 2020, 2019, and 2018, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.
(b)At Exelon and PHI, amortization of the unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.
The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ending December 31, | | Exelon | | Generation | | | | PHI |
| 2021 | | $ | (1) | | | $ | 81 | | | | | $ | (92) | |
| 2022 | | (22) | | | 57 | | | | | (89) | |
| 2023 | | (20) | | | 51 | | | | | (81) | |
| 2024 | | 20 | | | 48 | | | | | (38) | |
| 2025 | | 40 | | | 41 | | | | | (5) | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Intangible Assets
Renewable Energy Credits (Exelon and Generation)
Exelon’s and Generation’s RECs are included in Other current assets and Other deferred debits and other assets in the Consolidated Balance Sheets. Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer.
The following table presents the current and noncurrent RECs as of December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2020 | | As of December 31, 2019 |
| Exelon | | Generation | | Exelon | | Generation |
| Current REC's | $ | 632 | | | $ | 621 | | | $ | 345 | | | $ | 336 | |
| Noncurrent REC's | 0 | | | 0 | | | 86 | | | 86 | |
14. Income Taxes (All Registrants)
Components of Income Tax Expense or Benefit
Income tax expense (benefit) from continuing operations is comprised of the following components:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2020 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Included in operations: | | | | | | | | | | | | | | | | | |
| Federal | | | | | | | | | | | | | | | | | |
| Current | $ | 26 | | | $ | 130 | | | $ | (24) | | | $ | (7) | | | $ | 4 | | | $ | 25 | | | $ | 40 | | | $ | (13) | | | $ | (4) | |
| Deferred | 156 | | | 150 | | | 112 | | | 1 | | | 10 | | | (129) | | | (62) | | | (20) | | | (43) | |
| Investment tax credit amortization | (28) | | | (25) | | | (2) | | | 0 | | | 0 | | | (1) | | | 0 | | | 0 | | | 0 | |
| State | | | | | | | | | | | | | | | | | |
| Current | 42 | | | 40 | | | (27) | | | 0 | | | 0 | | | (5) | | | 0 | | | 0 | | | 0 | |
| Deferred | 177 | | | (46) | | | 118 | | | (24) | | | 27 | | | 33 | | | 15 | | | 8 | | | 6 | |
| Total | $ | 373 | | | $ | 249 | | | $ | 177 | | | $ | (30) | | | $ | 41 | | | $ | (77) | | | $ | (7) | | | $ | (25) | | | $ | (41) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2019 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Included in operations: | | | | | | | | | | | | | | | | | |
| Federal | | | | | | | | | | | | | | | | | |
| Current | $ | 85 | | | $ | 147 | | | $ | 59 | | | $ | 45 | | | $ | (51) | | | $ | 43 | | | $ | 16 | | | $ | 29 | | | $ | (3) | |
| Deferred | 489 | | | 346 | | | 15 | | | 20 | | | 95 | | | (34) | | | (6) | | | (21) | | | (6) | |
| Investment tax credit amortization | (72) | | | (69) | | | (2) | | | 0 | | | 0 | | | (1) | | | 0 | | | 0 | | | 0 | |
| State | | | | | | | | | | | | | | | | | |
| Current | 5 | | | 10 | | | (5) | | | 0 | | | 0 | | | 3 | | | 0 | | | 0 | | | 0 | |
| Deferred | 267 | | | 82 | | | 96 | | | 0 | | | 35 | | | 27 | | | 6 | | | 14 | | | 9 | |
| Total | $ | 774 | | | $ | 516 | | | $ | 163 | | | $ | 65 | | | $ | 79 | | | $ | 38 | | | $ | 16 | | | $ | 22 | | | $ | 0 | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2018 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Included in operations: | | | | | | | | | | | | | | | | | |
| Federal | | | | | | | | | | | | | | | | | |
| Current | $ | 226 | | | $ | 337 | | | $ | (63) | | | $ | 11 | | | $ | (5) | | | $ | (4) | | | $ | 28 | | | $ | (3) | | | $ | (14) | |
| Deferred | (99) | | | (347) | | | 145 | | | 10 | | | 47 | | | 23 | | | (22) | | | 13 | | | 18 | |
| Investment tax credit amortization | (24) | | | (21) | | | (2) | | | 0 | | | 0 | | | (1) | | | 0 | | | 0 | | | 0 | |
| State | | | | | | | | | | | | | | | | | |
| Current | (1) | | | 6 | | | (29) | | | 1 | | | 0 | | | 7 | | | 0 | | | 0 | | | 0 | |
| Deferred | 16 | | | (83) | | | 117 | | | (16) | | | 32 | | | 8 | | | 5 | | | 12 | | | 8 | |
| Total | $ | 118 | | | $ | (108) | | | $ | 168 | | | $ | 6 | | | $ | 74 | | | $ | 33 | | | $ | 11 | | | $ | 22 | | | $ | 12 | |
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2020(a) |
| Exelon | | Generation | | ComEd(b) | | PECO(c) | | BGE(d) | | PHI(d) | | Pepco(d) | | DPL(d) | | ACE(d) |
| U.S. federal statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
| State income taxes, net of Federal income tax benefit | 7.8 | | | 0.5 | | | 11.6 | | | (4.5) | | | 5.5 | | | 5.1 | | | 4.5 | | | 6.6 | | | 7.0 | |
| Qualified NDT fund income | 8.4 | | | 23.5 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred Prosecution Agreement payments | 1.8 | | | 0 | | | 6.8 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.1) | | | (2.6) | | | (0.3) | | | 0 | | | (0.1) | | | (0.2) | | | (0.1) | | | (0.3) | | | (0.5) | |
| Plant basis differences | (4.0) | | | 0 | | | (0.6) | | | (18.7) | | | (1.5) | | | (1.6) | | | (1.7) | | | (0.4) | | | (3.0) | |
| Production tax credits and other credits | (2.2) | | | (5.4) | | | (0.3) | | | 0 | | | (0.4) | | | (0.3) | | | (0.3) | | | (0.3) | | | (0.5) | |
| Noncontrolling interests | 1.1 | | | 3.2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Excess deferred tax amortization | (13.6) | | | 0 | | | (11.2) | | | (4.6) | | | (13.9) | | | (42.0) | | | (25.4) | | | (51.7) | | | (82.1) | |
| Tax settlements | (3.7) | | | (10.3) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Other | 0.5 | | | (0.1) | | | 1.8 | | | (0.4) | | | (0.1) | | | (0.4) | | | (0.7) | | | 0.1 | | | 0.4 | |
| Effective income tax rate | 16.0 | % | | 29.8 | % | | 28.8 | % | | (7.2) | % | | 10.5 | % | | (18.4) | % | | (2.7) | % | | (25.0) | % | | (57.7) | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2019(a) |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| U.S. federal statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
| State income taxes, net of Federal income tax benefit | 5.4 | | | 3.8 | | | 8.5 | | | 0 | | | 6.4 | | | 4.7 | | | 2.0 | | | 6.8 | | | 7.0 | |
| Qualified NDT fund income | 5.9 | | | 12.3 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.5) | | | (3.0) | | | (0.2) | | | 0 | | | (0.1) | | | (0.2) | | | (0.1) | | | (0.2) | | | (0.3) | |
| Plant basis differences | (1.4) | | | 0 | | | 0 | | | (7.2) | | | (1.2) | | | (1.2) | | | (1.8) | | | (0.4) | | | (0.7) | |
| Production tax credits and other credits | (3.1) | | | (4.8) | | | (1.2) | | | 0 | | | (1.3) | | | (0.2) | | | (0.1) | | | 0 | | | (0.1) | |
| Noncontrolling interests | (0.6) | | | (1.2) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Excess deferred tax amortization | (5.5) | | | 0 | | | (9.7) | | | (2.8) | | | (6.8) | | | (17.5) | | | (15.1) | | | (14.2) | | | (27.0) | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Other | (0.8) | | | (1.2) | | | 0.8 | | | 0 | | | 0 | | | 0.8 | | | 0.3 | | | 0 | | | 0.1 | |
| Effective income tax rate | 19.4 | % | | 26.9 | % | | 19.2 | % | | 11.0 | % | | 18.0 | % | | 7.4 | % | | 6.2 | % | | 13.0 | % | | 0 | % |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2018(a) |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| U.S. federal statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
| State income taxes, net of Federal income tax benefit | 0.5 | | | (16.6) | | | 8.3 | | | (2.6) | | | 6.6 | | | 2.9 | | | 2.0 | | | 6.7 | | | 7.4 | |
| Qualified NDT fund income | (1.9) | | | (11.8) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.2) | | | (6.5) | | | (0.2) | | | (0.1) | | | (0.1) | | | (0.2) | | | (0.1) | | | (0.3) | | | (0.4) | |
| Plant basis differences | (3.5) | | | 0 | | | (0.2) | | | (14.1) | | | (1.3) | | | (1.6) | | | (2.8) | | | (0.3) | | | (0.5) | |
| Production tax credits and other credits | (2.2) | | | (13.5) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Noncontrolling interests | (1.0) | | | (6.1) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Excess deferred tax amortization | (8.3) | | | 0 | | | (9.1) | | | (3.2) | | | (8.0) | | | (14.8) | | | (15.3) | | | (12.0) | | | (14.9) | |
| Tax Cuts and Jobs Act of 2017 | 0.9 | | | 2.7 | | | (0.1) | | | 0 | | | 0 | | | 0.1 | | | 0 | | | 0 | | | 0 | |
| Other | 1.0 | | | 1.3 | | | 0.5 | | | 0.3 | | | 0.9 | | | 0.4 | | | 0.3 | | | 0.4 | | | 1.2 | |
| Effective income tax rate | 5.3 | % | | (29.5) | % | | 20.2 | % | | 1.3 | % | | 19.1 | % | | 7.8 | % | | 5.1 | % | | 15.5 | % | | 13.8 | % |
__________
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. See Note 19 — Commitments and Contingencies for additional information.
(c)At PECO, the negative effective tax rate is primarily related to an increase in plant basis differences attributable to tax repair deductions related to an increase in storms and qualifying projects.
(d)At BGE, the lower effective tax rate, and at PHI, Pepco, DPL, and ACE, the negative effective tax rate is primarily attributable to accelerated amortization of transmission related income tax regulatory liabilities as a result of regulatory settlements. See Note 3 — Regulatory Matters for additional information.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
Tax Differences and Carryforwards
The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2020 and 2019 are presented below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2020 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Plant basis differences | $ | (13,868) | | | $ | (2,592) | | | $ | (4,432) | | | $ | (2,131) | | | $ | (1,711) | | | $ | (2,822) | | | $ | (1,259) | | | $ | (806) | | | $ | (725) | |
| Accrual based contracts | 40 | | | (37) | | | 0 | | | 0 | | | 0 | | | 77 | | | 0 | | | 0 | | | 0 | |
| Derivatives and other financial instruments | 41 | | | (41) | | | 84 | | | 0 | | | 0 | | | 2 | | | 0 | | | 0 | | | 0 | |
| Deferred pension and postretirement obligation | 1,559 | | | (236) | | | (288) | | | (30) | | | (33) | | | (80) | | | (74) | | | (40) | | | (7) | |
| Nuclear decommissioning activities | (742) | | | (742) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred debt refinancing costs | 169 | | | 16 | | | (6) | | | 0 | | | (2) | | | 131 | | | (3) | | | (1) | | | (1) | |
| Regulatory assets and liabilities | (1,107) | | | 0 | | | 87 | | | (231) | | | 142 | | | (41) | | | 38 | | | 67 | | | 46 | |
| Tax loss carryforward | 286 | | | 55 | | | 0 | | | 47 | | | 57 | | | 90 | | | 4 | | | 49 | | | 38 | |
| Tax credit carryforward | 841 | | | 838 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Investment in partnerships | (835) | | | (813) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Other, net | 1,070 | | | 347 | | | 223 | | | 104 | | | 29 | | | 220 | | | 107 | | | 18 | | | 27 | |
| Deferred income tax liabilities (net) | $ | (12,546) | | | $ | (3,205) | | | $ | (4,332) | | | $ | (2,241) | | | $ | (1,518) | | | $ | (2,423) | | | $ | (1,187) | | | $ | (713) | | | $ | (622) | |
Unamortized investment tax credits(a) | (464) | | | (445) | | | (9) | | | (1) | | | (3) | | | (6) | | | (2) | | | (2) | | | (3) | |
| Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (13,010) | | | $ | (3,650) | | | $ | (4,341) | | | $ | (2,242) | | | $ | (1,521) | | | $ | (2,429) | | | $ | (1,189) | | | $ | (715) | | | $ | (625) | |
__________
(a)Does not include unamortized investment tax credits reclassified to liabilities held for sale.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2019 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Plant basis differences | $ | (13,413) | | | $ | (2,814) | | | $ | (4,197) | | | $ | (1,978) | | | $ | (1,578) | | | $ | (2,681) | | | $ | (1,204) | | | $ | (753) | | | $ | (687) | |
| Accrual based contracts | 61 | | | (43) | | | 0 | | | 0 | | | 0 | | | 104 | | | 0 | | | 0 | | | 0 | |
| Derivatives and other financial instruments | 165 | | | 88 | | | 84 | | | 0 | | | 0 | | | 2 | | | 0 | | | 0 | | | 0 | |
| Deferred pension and postretirement obligation | 1,504 | | | (220) | | | (270) | | | (28) | | | (28) | | | (89) | | | (75) | | | (42) | | | (10) | |
| Nuclear decommissioning activities | (503) | | | (503) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred debt refinancing costs | 183 | | | 20 | | | (7) | | | 0 | | | (3) | | | 142 | | | (3) | | | (2) | | | (1) | |
| Regulatory assets and liabilities | (884) | | | 0 | | | 183 | | | (169) | | | 157 | | | (10) | | | 55 | | | 88 | | | 77 | |
| Tax loss carryforward | 240 | | | 55 | | | 0 | | | 25 | | | 49 | | | 93 | | | 13 | | | 44 | | | 31 | |
| Tax credit carryforward | 892 | | | 897 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Investment in partnerships | (830) | | | (808) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Other, net | 926 | | | 236 | | | 196 | | | 70 | | | 10 | | | 181 | | | 85 | | | 12 | | | 16 | |
| Deferred income tax liabilities (net) | $ | (11,659) | | | $ | (3,092) | | | $ | (4,011) | | | $ | (2,080) | | | $ | (1,393) | | | $ | (2,258) | | | $ | (1,129) | | | $ | (653) | | | $ | (574) | |
| Unamortized investment tax credits | (668) | | | (648) | | | (10) | | | (1) | | | (3) | | | (7) | | | (2) | | | (2) | | | (3) | |
Total deferred income tax liabilities (net) and
unamortized investment tax credits | $ | (12,327) | | | $ | (3,740) | | | $ | (4,021) | | | $ | (2,081) | | | $ | (1,396) | | | $ | (2,265) | | | $ | (1,131) | | | $ | (655) | | | $ | (577) | |
The following table provides Exelon’s, Generation’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s, and ACE’s carryforwards, which are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2020. ComEd does not have net operating losses or credit carryforwards for the year ended December 31, 2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Federal | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Federal general business credits carryforwards and other carryforwards | $ | 858 | | | $ | 852 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| State | | | | | | | | | | | | | | | |
| State net operating losses and other carryforwards | 5,202 | | | 1,118 | | | 616 | | | 902 | | | 1,436 | | | 63 | | | 728 | | | 531 | |
| Deferred taxes on state tax attributes (net) | 324 | | | 76 | | | 49 | | | 59 | | | 98 | | | 4 | | | 49 | | | 38 | |
| Valuation allowance on state tax attributes | 27 | | | 23 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Year in which net operating loss or credit carryforwards will begin to expire(a) | 2034 | | 2034 | | 2032 | | 2033 | | 2029 | | 2029 | | 2032 | | 2031 |
__________
(a)Generation's state net operating loss carryforwards will begin expiring in 2029. PECO's Pennsylvania charitable contribution carryforwards and BGE's Maryland charitable deduction and capital loss carryforwards will begin expiring in 2021. ACE's New Jersey tax credit carryforward has an indefinite carryforward period. These amounts are not material.
Tabular Reconciliation of Unrecognized Tax Benefits
The following table presents changes in unrecognized tax benefits, by Registrant.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
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| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance at January 1, 2018 | $ | 743 | | | $ | 468 | | | $ | 2 | | | $ | 0 | | | $ | 120 | | | $ | 125 | | | $ | 59 | | | $ | 21 | | | $ | 14 | |
| Change to positions that only affect timing | 15 | | | 15 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Increases based on tax positions prior to 2018 | 30 | | | 21 | | | 0 | | | 0 | | | 0 | | | 8 | | | 7 | | | 1 | | | 0 | |
Decreases based on tax positions prior to 2018(a) | (251) | | | (36) | | | 0 | | | 0 | | | (120) | | | (88) | | | (66) | | | (22) | | | 0 | |
| Decrease from settlements with taxing authorities | (53) | | | (53) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Decreases from expiration of statute of limitations | (7) | | | (7) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance at December 31, 2018 | 477 | | | 408 | | | 2 | | | 0 | | | 0 | | | 45 | | | 0 | | | 0 | | | 14 | |
| Change to positions that only affect timing | 26 | | | 12 | | | 3 | | | 1 | | | 4 | | | 3 | | | 2 | | | 1 | | | 0 | |
| Increases based on tax positions related to 2019 | 2 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Increases based on tax positions prior to 2019 | 34 | | | 19 | | | 3 | | | 2 | | | 3 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Decreases based on tax positions prior to 2019 | (3) | | | (3) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Decrease from settlements with taxing authorities | (29) | | | 4 | | | (2) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance at December 31, 2019 | 507 | | | 441 | | | 6 | | | 3 | | | 7 | | | 48 | | | 2 | | | 1 | | | 14 | |
| Change to positions that only affect timing | 6 | | | 0 | | | 2 | | | 3 | | | 3 | | | 3 | | | 1 | | | 0 | | | 1 | |
| Increases based on tax positions related to 2020 | 3 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Increases based on tax positions prior to 2020 | 26 | | | 23 | | | 1 | | | 0 | | | 0 | | | 1 | | | 0 | | | 0 | | | 0 | |
Decreases based on tax positions prior to 2020(b) | (348) | | | (346) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Decrease from settlements with taxing authorities(b) | (69) | | | (69) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Balance at December 31, 2020 | $ | 125 | | | $ | 50 | | | $ | 9 | | | $ | 6 | | | $ | 10 | | | $ | 52 | | | $ | 3 | | | $ | 1 | | | $ | 15 | |
__________
(a)Exelon, Generation, BGE, PHI, Pepco, and DPL decreased their unrecognized state tax benefits primarily due to the receipt of favorable guidance with respect to the deductibility of certain depreciable fixed assets. The recognition of the tax benefits related to BGE, PHI, Pepco, and DPL was offset by corresponding regulatory liabilities and that portion had no immediate impact to their effective tax rate.
(b)Exelon's and Generation's unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $411 million due to the settlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase to Exelon's and Generation’s net income of $76 million and $73 million, respectively, in the first quarter of 2020, reflecting a decrease to Exelon's and Generation's income tax expense of $67 million.
Like-Kind Exchange
In 2016, the Tax Court held that Exelon was not entitled to defer a gain on its 1999 like-kind exchange transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for penalties and interest on the penalties. Exelon had fully paid the amounts assessed resulting from the Tax Court decision in 2017. In September 2017, Exelon appealed the Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
Tax Court’s decision. Exelon filed a petition seeking rehearing of the Seventh Circuit’s decision, but the Seventh Circuit denied that petition in December 2018. In the first quarter of 2019, Exelon elected not to seek a further review by the U.S. Supreme Court. As a result, Exelon's and ComEd's unrecognized tax benefits decreased by approximately $33 million and $2 million, respectively, in the first quarter of 2019.
Recognition of unrecognized tax benefits
The following table presents Exelon's, Generation's, and PHI's unrecognized tax benefits that, if recognized, would decrease the effective tax rate. ComEd's, PECO's, BGE's, Pepco's, DPL's, and ACE's amounts are not material.
| | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | PHI(a) | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| December 31, 2020 | $ | 73 | | | $ | 39 | | | $ | 33 | | | | | | | |
| December 31, 2019 | 462 | | | 429 | | | 32 | | | | | | | |
| December 31, 2018 | 463 | | | 408 | | | 31 | | | | | | | |
__________
(a)PHI has $21 million of unrecognized state tax benefits that, if recognized, $14 million would be in the form of a net operating loss carryforward, which is expected to require a full valuation allowance based on present circumstances.
ACE has $14 million of unrecognized tax benefits as of December 31, 2020, 2019 and 2018 that, if recognized, may be included in future base rates and that portion would have no impact on the effective tax rate. Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI's, Pepco's, and DPL's amounts are not material.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
As of December 31, 2020, ACE has approximately $14 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date based on the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Total amounts of interest and penalties recognized
The following table represents the net interest and penalties receivable (payable) related to tax positions reflected in Exelon's Consolidated Balance Sheets. Generation's and the Utility Registrants' amounts are not material.
| | | | | |
| Net interest and penalties receivable as of | Exelon |
| December 31, 2020 | $ | 314 | |
| December 31, 2019 | 318 | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
The Registrants did not record material interest and penalty expense related to tax positions reflected in their Consolidated Balance Sheets. Interest expense and penalty expense are recorded in Interest expense, net and Other, net, respectively, in Other income and deductions in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
Description of tax years open to assessment by major jurisdiction
| | | | | | | | | | | |
| Major Jurisdiction | Open Years | | Registrants Impacted |
Federal consolidated income tax returns(a) | 2010-2019 | | All Registrants |
| Delaware separate corporate income tax returns | Same as federal | | DPL |
District of Columbia occupied by an active substation and formercombined corporate income tax returns | 2017-2019 | | Exelon, PHI, Pepco operated steam plant building, which |
| Illinois unitary corporate income tax returns | 2012-2019 | | Exelon, Generation, ComEd |
| Maryland separate company corporate net income tax returns | Same as federal | | BGE, Pepco, retired and closed in 1981.DPL |
| New Jersey separate corporate income tax returns | 2013-2019 | | Exelon, Generation |
| New Jersey separate corporate income tax returns | 2014-2019 | | ACE |
| New York combined corporate income tax returns | 2010-March 2012 | | Exelon, Generation |
| New York combined corporate income tax returns | 2011-2019 | | Exelon, Generation |
| Pennsylvania separate corporate income tax returns | 2011-2019 | | Exelon, Generation |
| Pennsylvania separate corporate income tax returns | 2017-2019 | | PECO |
16.__________
(a)Certain registrants are only open to assessment for tax years since joining the Exelon federal consolidated group; BGE beginning in 2012 and PHI, Pepco, DPL, and ACE beginning in 2016.
Other Tax Matters
Long-Term Marginal State Income Tax Rate (All Registrants)
Quarterly, Exelon reviews and updates its marginal state income tax rates for changes in state apportionment. The Registrants remeasure their existing deferred income tax balances to reflect the changes in marginal rates, which results in either an increase or a decrease to their net deferred income tax liability balances. Utility Registrants record corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts. The impacts to the Utility Registrants for the years ended December 31, 2020, 2019, and 2018 were not material.
| | | | | | | | | | | | | | | |
| December 31, 2020 | Exelon | | Generation | | | | |
| Increase (decrease) to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes | $ | 66 | | | $ | (26) | | | | | |
| | | | | | | |
| December 31, 2019 | | | | | | | |
| Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes | $ | 23 | | | $ | 9 | | | | | |
| | | | | | | |
| December 31, 2018 | | | | | | | |
| Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes | $ | (50) | | | $ | (53) | | | | | |
| | | | | | | |
Allocation of Tax Benefits (All Registrants)
Generation and the Utility Registrants are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net federal and state benefits attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit.
The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
December 31, 2020(a) | $ | 64 | | | $ | 14 | | | $ | 17 | | | $ | 0 | | | $ | 17 | | | $ | 8 | | | $ | 6 | | | $ | 1 | |
December 31, 2019(b) | 41 | | | 0 | | | 14 | | | 3 | | | 7 | | | 6 | | | 1 | | | 0 | |
December 31, 2018(c) | 155 | | | 1 | | | 48 | | | 26 | | | 2 | | | 0 | | | 0 | | | 0 | |
__________
(a)BGE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
(b)ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
(c)Pepco, DPL, and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
Research and Development Activities
In the fourth quarter of 2019, Exelon and Generation recognized additional tax benefits related to certain research and development activities that qualify for federal and state tax incentives for the 2010 through 2018 tax years, which resulted in an increase to Exelon’s and Generation’s net income of $108 million and $75 million, respectively, for the year ended December 31, 2019, reflecting a decrease to Exelon’s and Generation’s Income tax expense of $97 million and $66 million, respectively.
15. Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and other postretirement benefitOPEB plans for essentially all current employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
employees participate in cash balance pension plans. Effective February 1, 2018 for most newly-hired Generation and BSC non-represented, non-craft, employees and January 1, 2021 for most newly-hired utility management employees, these newly-hired employees are not eligible for pension benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits. Effective January 1, 2021, most non-represented, non-craft, employees who are under the age of 40 are not eligible for retiree health care benefits.
Effective January 1, 2019, Exelon is mergingmerged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans isdid not changingchange the benefits offered to the plan participants and, thus, hashad no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP will beare amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
The table below shows the pension and other postretirement benefitOPEB plans in which employees of each operating company participated at December 31, 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Operating Company(e) |
| Name of Plan: | | Generation | | ComEdGeneration | | PECOComEd | | BGEPECO | | BSCBGE | | PHI | | Pepco | | DPL | | ACE |
| Qualified Pension Plans: | | | | | | | | | | | | | | | | | | |
Exelon Corporation Retirement Program(a) | | X | | X | | X | | X | | X | | X | | X | | X | | X |
Exelon Corporation Cash Balance Pension Plan(a)
| | X | | X | | X | | X | | X | | X | | X | | X | | X |
Exelon Corporation Pension Plan for Bargaining Unit Employees(a) | | X | | X | | X | | | | X | | | | | | | | |
Exelon New England Union Employees Pension Plan(a) | | X | | X | | | | | | | | | | | | | | |
Exelon Employee Pension Plan for Clinton, TMI, and Oyster Creek(a) | | X | | X | | X | | X | | X | | X | | | | | | X |
Pension Plan of Constellation Energy Group, Inc.(b) | | X | | X | | X | | X | | X | | X | | X | | X | | |
Pension Plan of Constellation Energy Nuclear Group, LLC(c) | | X | | X | | X | | X | | X | | X | | X | | | | |
Nine Mile Point Pension Plan(c) | | X | | X | | | | | | X | | | | | | | | |
Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B(b) | | X | | X | | | | | | | | | | | | | | |
Pepco Holdings LLC Retirement Plan(d) | | X | | X | | X | | X | | X | | X | | X | | X | | X |
| Non-Qualified Pension Plans: | | | | | | | | | | | | | | | | | | |
Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan(a) | | X | | X | | X | | X | | X | | X | | | | | | |
Exelon Corporation Supplemental Management Retirement Plan(a) | | X | | X | | X | | X | | X | | X | | X | | | | X |
Constellation Energy Group, Inc. Senior Executive Supplemental Plan(b) | | X | | X | | | | X | | X | | X | | | | | | |
Constellation Energy Group, Inc. Supplemental Pension Plan(b) | | X | | X | | | | X | | X | | X | | | | | | |
Constellation Energy Group, Inc. Benefits Restoration Plan(b) | | X | | X | | X | | X | | X | | X | | | | | | |
Constellation Energy Nuclear Plan, LLC Executive Retirement Plan(c) | | X | | X | | | | | | X | | X | | | | | | |
Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan(c) | | X | | X | | | | | | X | | X | | | | | | |
Baltimore Gas & Electric Company Executive Benefit Plan(b) | | X | | X | | | | X | | X | | | | | | | | |
Baltimore Gas & Electric Company Manager Benefit Plan(b) | | X | | X | | X | | X | | X | | | | | | | | |
Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan(d) | | | | X | | | | | | X | | X | | X | | X | | X |
Conectiv Supplemental Executive Retirement Plan(d) | | X | | X | | | | | | X | | X | | | | X | | X |
Pepco Holdings LLC Combined Executive Retirement Plan(d) | | | | | | | | | | X | | X | | X | | | | |
Atlantic City Electric Director Retirement Plan(d) | | | | | | | | | | | | | | | | | | X |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Operating Company(e) |
| Name of Plan: | | Generation | | ComEdGeneration | | PECOComEd | | BGEPECO | | BSCBGE | | PHI | | Pepco | | DPL | | ACE |
Other Postretirement BenefitOPEB Plans: | | | | | | | | | | | | | | | | | | |
PECO Energy Company Retiree Medical Plan(a) | | X | | X | | X | | X | | X | | X | | X | | X | | X |
Exelon Corporation Health Care Program(a) | | X | | X | | X | | X | | X | | X | | X | | | | X |
Exelon Corporation Employees’ Life Insurance Plan(a) | | X | | X | | X | | X | | X | | | | | | | | |
Exelon Corporation Health Reimbursement Arrangement Plan(a) | | X | | X | | X | | X | | X | | | | | | | | |
Constellation Energy Group, Inc. Retiree Medical Plan(b) | | X | | X | | X | | X | | X | | X | | X | | | | |
Constellation Energy Group, Inc. Retiree Dental Plan(b) | | X | | X | | | | X | | X | | | | | | | | |
Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan(b) | | X | | X | | X | | X | | X | | X | | X | | | | |
Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan(b) | | X | | X | | | | | | X | | | | | | | | |
Exelon New England Union Post-Employment Medical Savings Account Plan(a) | | X | | X | | | | | | | | | | | | | | |
Retiree Medical Plan of Constellation Energy Nuclear Group, LLC(c) | | X | | X | | X | | X | | X | | | | X | | | | |
Retiree Dental Plan of Constellation Energy Nuclear Group, LLC(c) | | X | | X | | X | | X | | X | | | | X | | | | |
Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees(c) | | X | | X | | | | | | X | | | | | | | | |
Pepco Holdings LLC Welfare Plan for Retirees(d) | | X | | X | | X | | X | | X | | X | | X | | X | | X |
________________________________
| |
(a) | These plans are collectively referred to as the legacy Exelon plans. |
| |
(b) | These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans. |
| |
(c) | These plans are collectively referred to as the legacy CENG plans. |
| |
(d) | These plans are collectively referred to as the legacy PHI plans. |
| |
(e) | Employees generally remain in their legacy benefit plans when transferring between operating companies. |
(a)These plans are collectively referred to as the legacy Exelon plans.
(b)These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans.
(c)These plans are collectively referred to as the legacy CENG plans.
(d)These plans are collectively referred to as the legacy PHI plans.
(e)Employees generally remain in their legacy benefit plans when transferring between operating companies.
Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Exelon has elected that the trusts underlying these plans be treated as qualified trusts under the IRC. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations.
Benefit Obligations, Plan Assets, and Funded Status
During the first quarter of 2020, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2020. This valuation resulted in an increase to the pension and OPEB obligations of $8 million and $31 million, respectively. Additionally, accumulated other comprehensive loss increased by $7 million (after-tax) and regulatory assets and liabilities increased by $19 million and decreased by $10 million, respectively.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
The following tables provide a rollforward of the changes in the benefit obligations and plan assets of Exelon for the most recent two years for all plans combined:
| | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2020 | | 2019 |
| Change in benefit obligation: | | | | | | | |
| Net benefit obligation at beginning of year | $ | 22,868 | | | $ | 20,692 | | | $ | 4,658 | | | $ | 4,369 | |
| Service cost | 387 | | | 357 | | | 90 | | | 93 | |
| Interest cost | 757 | | | 883 | | | 154 | | | 188 | |
| Plan participants’ contributions | 0 | | | 0 | | | 49 | | | 44 | |
Actuarial loss(a) | 2,217 | | | 2,322 | | | 49 | | | 250 | |
| Plan amendments | 0 | | | 68 | | | (111) | | | 0 | |
| | | | | | | |
| Curtailments | 0 | | | (3) | | | 0 | | | 0 | |
| Settlements | (45) | | | (35) | | | (5) | | | (4) | |
| Contractual termination benefits | 0 | | | 1 | | | 0 | | | 0 | |
| Gross benefits paid | (1,290) | | | (1,417) | | | (280) | | | (282) | |
| Net benefit obligation at end of year | $ | 24,894 | | | $ | 22,868 | | | $ | 4,604 | | | $ | 4,658 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2020 | | 2019 |
| Change in plan assets: | | | | | | | |
| Fair value of net plan assets at beginning of year | $ | 18,590 | | | $ | 16,678 | | | $ | 2,541 | | | $ | 2,408 | |
| Actual return on plan assets | 2,547 | | | 3,008 | | | 190 | | | 324 | |
| Employer contributions | 542 | | | 356 | | | 59 | | | 51 | |
| Plan participants’ contributions | 0 | | | 0 | | | 49 | | | 44 | |
| Gross benefits paid | (1,290) | | | (1,417) | | | (280) | | | (282) | |
| | | | | | | |
| Settlements | (45) | | | (35) | | | (5) | | | (4) | |
| Fair value of net plan assets at end of year | $ | 20,344 | | | $ | 18,590 | | | $ | 2,554 | | | $ | 2,541 | |
__________
(a)The pension and OPEB actuarial losses in 2020 and 2019 primarily reflect a decrease in the discount rate. OPEB losses in 2020 were offset by gains related to plan changes.
Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2020 | | 2019 |
| Other current liabilities | $ | 47 | | | $ | 31 | | | $ | 42 | | | $ | 41 | |
| Pension obligations | 4,503 | | | 4,247 | | | 0 | | | 0 | |
| Non-pension postretirement benefit obligations | 0 | | | 0 | | | 2,008 | | | 2,076 | |
| Unfunded status (net benefit obligation less plan assets) | $ | 4,550 | | | $ | 4,278 | | | $ | 2,050 | | | $ | 2,117 | |
The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. Information for pension and OPEB plans with projected benefit obligations (PBO) and accumulated postretirement benefit obligation (APBO), respectively, in excess of plan assets has been disclosed in the Obligations and Plan Assets table above as all pension and OPEB plans are underfunded.
| | | | | | | | | | | | | |
| ABO in excess of plan assets | Exelon | | |
| 2020 | | 2019 | | |
| | | | | |
| ABO | $ | 23,514 | | | $ | 21,727 | | | |
| Fair value of net plan assets | 20,344 | | | 18,590 | | | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Components of Net Periodic Benefit Costs
The majority of the 2020 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.34%. The majority of the 2020 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.69% for funded plans and a discount rate of 3.31%.
A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2020, 2019, and 2018.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB |
| 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 |
| Components of net periodic benefit cost: | | | | | | | | | | | |
| Service cost | $ | 387 | | | $ | 357 | | | $ | 405 | | | $ | 90 | | | $ | 93 | | | $ | 112 | |
| Interest cost | 757 | | | 883 | | | 802 | | | 154 | | | 188 | | | 175 | |
| Expected return on assets | (1,270) | | | (1,225) | | | (1,252) | | | (163) | | | (153) | | | (173) | |
| Amortization of: | | | | | | | | | | | |
| | | | | | | | | | | |
| Prior service cost (credit) | 4 | | | 0 | | | 2 | | | (124) | | | (179) | | | (186) | |
| Actuarial loss | 512 | | | 414 | | | 629 | | | 49 | | | 45 | | | 66 | |
| Curtailment benefits | 0 | | | 0 | | | 0 | | | (1) | | | 0 | | | 0 | |
| Settlement and other charges | 14 | | | 17 | | | 3 | | | 1 | | | 1 | | | 1 | |
| Contractual termination benefits | 0 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Net periodic benefit cost | $ | 404 | | | $ | 447 | | | $ | 589 | | | $ | 6 | | | $ | (5) | | | $ | (5) | |
Cost Allocation to Exelon Subsidiaries
All Registrants account for their participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocates costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan.
The amounts below represent the Registrants' allocated pension and OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For Generation and the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2020 | $ | 411 | | | $ | 115 | | | $ | 114 | | | $ | 5 | | | $ | 64 | | | $ | 70 | | | $ | 15 | | | $ | 7 | | | $ | 14 | |
| 2019 | 442 | | | 135 | | | 96 | | | 12 | | | 61 | | | 95 | | | 25 | | | 15 | | | 16 | |
| 2018 | 583 | | | 204 | | | 177 | | | 18 | | | 60 | | | 67 | | | 15 | | | 6 | | | 12 | |
Components of AOCI and Regulatory Assets
Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its balance sheet, with offsetting entries to AOCI and regulatory assets (liabilities), in accordance with the applicable authoritative guidance. The measurement date for the plans is December 31.
During the first quarter of 2018, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2018. This valuation resulted in an increase to the pension and OPEB obligations of $23 million and $14 million, respectively. Additionally, accumulated other comprehensive loss decreased by $18 million (after-tax) and regulatory assets and liabilities increased by $61 million and $1 million, respectively.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
In connection with the acquisition of FitzPatrick in 2017, Exelon recorded pension and OPEB obligations for FitzPatrick employees of $16 million and $17 million, respectively. See Note 5 — Mergers, Acquisitions and Dispositions for additional information of the acquisition of FitzPatrick.
The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for all plans combined:
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| Exelon | 2018 | | 2017 | | 2018 | | 2017 |
| Change in benefit obligation: | | | | | | | |
| Net benefit obligation at beginning of year | $ | 22,337 |
| | $ | 21,060 |
| | $ | 4,856 |
| | $ | 4,457 |
|
| Service cost | 405 |
| | 387 |
|
| 112 |
| | 106 |
|
| Interest cost | 802 |
| | 842 |
|
| 175 |
| | 182 |
|
| Plan participants’ contributions | — |
| | — |
| | 45 |
| | 53 |
|
Actuarial (gain) loss(a) | (1,561 | ) | | 1,182 |
| | (540 | ) | | 350 |
|
| Plan amendments | (4 | ) | | 9 |
| | — |
| | — |
|
Acquisitions(b) | — |
| | 16 |
| | — |
| | 17 |
|
| Settlements | (48 | ) | | (34 | ) |
| (4 | ) | | — |
|
| Gross benefits paid | (1,239 | ) | | (1,125 | ) |
| (275 | ) | | (309 | ) |
| Net benefit obligation at end of year | $ | 20,692 |
| | $ | 22,337 |
| | $ | 4,369 |
| | $ | 4,856 |
|
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| Exelon | 2018 | | 2017 | | 2018 | | 2017 |
| Change in plan assets: | | | | | | | |
| Fair value of net plan assets at beginning of year | $ | 18,573 |
| | $ | 16,791 |
| | $ | 2,732 |
| | $ | 2,578 |
|
| Actual return on plan assets | (945 | ) | | 2,600 |
| | (136 | ) | | 346 |
|
| Employer contributions | 337 |
|
| 341 |
|
| 46 |
|
| 64 |
|
| Plan participants’ contributions | — |
| | — |
| | 45 |
| | 53 |
|
| Gross benefits paid | (1,239 | ) |
| (1,125 | ) |
| (275 | ) |
| (309 | ) |
| Settlements | (48 | ) |
| (34 | ) |
| (4 | ) |
| — |
|
| Fair value of net plan assets at end of year | $ | 16,678 |
| | $ | 18,573 |
| | $ | 2,408 |
| | $ | 2,732 |
|
__________
| |
(a) | The pension actuarial gain in 2018 primarily reflects an increase in the discount rate. The OPEB actuarial gain in 2018 primarily reflects an increase in the discount rate and favorable health care claims experience. The pension and OPEB actuarial losses in 2017 primarily reflect a decrease in the discount rate. |
| |
(b) | Exelon recorded pension and OPEB obligations associated with its acquisition of Fitzpatrick on March 31, 2017. |
Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| Exelon | 2018 | | 2017 | | 2018 | | 2017 |
| Other current liabilities | $ | 26 |
| | $ | 28 |
| | $ | 33 |
| | $ | 31 |
|
| Pension obligations | 3,988 |
|
| 3,736 |
|
| — |
|
| — |
|
| Non-pension postretirement benefit obligations | — |
| | — |
| | 1,928 |
|
| 2,093 |
|
| Unfunded status (net benefit obligation less plan assets) | $ | 4,014 |
|
| $ | 3,764 |
|
| $ | 1,961 |
|
| $ | 2,124 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plan. The funded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.
The following tables provide the projected benefit obligations (PBO), accumulated benefit obligation (ABO), and fair value of plan assets for all pension plans with a PBO or ABO in excess of plan assets.
|
| | | | | | | |
| PBO in excess of plan assets | Exelon |
| | 2018 | | 2017 |
| Projected benefit obligation | $ | 20,692 |
| | $ | 22,337 |
|
| Fair value of net plan assets | 16,678 |
| | 18,573 |
|
|
| | | | | | | |
| ABO in excess of plan assets | Exelon |
| | 2018 | | 2017 |
| Projected benefit obligation | $ | 20,692 |
| | $ | 22,337 |
|
| Accumulated benefit obligation | 19,656 |
| | 21,153 |
|
| Fair value of net plan assets | 16,678 |
| | 18,573 |
|
On a PBO basis, the Exelon plans were funded at 81% and 83% at December 31, 2018 and 2017, respectively. On an ABO basis, the Exelon plans were funded at 85% and 88% at December 31, 2018 and 2017, respectively. The ABO differs from the PBO in that the ABO includes no assumption about future compensation levels.
Components of Net Periodic Benefit Costs
The majority of the 2018 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.62%. The majority of the 2018 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.60% for funded plans and a discount rate of 3.61%.
A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following tables present the components of Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2018, 2017 and 2016 and PHI's net periodic benefit costs, prior to capitalization, for the predecessor period of January 1, 2016 to March 23, 2016.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| Exelon | 2018 | | 2017(a) | | 2016(b) | | 2018 | | 2017(a) | | 2016(b) |
| Components of net periodic benefit cost: | | | | | | | | | | | |
| Service cost | $ | 405 |
|
| $ | 387 |
|
| $ | 354 |
|
| $ | 112 |
|
| $ | 106 |
|
| $ | 107 |
|
| Interest cost | 802 |
|
| 842 |
|
| 830 |
|
| 175 |
|
| 182 |
|
| 185 |
|
| Expected return on assets | (1,252 | ) | | (1,196 | ) | | (1,141 | ) | | (173 | ) | | (162 | ) | | (162 | ) |
| Amortization of: | | | | | | | | | | | |
| Prior service cost (credit) | 2 |
| | 1 |
| | 14 |
| | (186 | ) | | (188 | ) | | (185 | ) |
| Actuarial loss | 629 |
| | 607 |
| | 554 |
| | 66 |
| | 61 |
| | 63 |
|
Settlement and other charges(c) | 3 |
| | 3 |
| | 2 |
| | 1 |
| | — |
| | — |
|
| Net periodic benefit cost | $ | 589 |
| | $ | 644 |
| | $ | 613 |
| | $ | (5 | ) | | $ | (1 | ) | | $ | 8 |
|
__________
| |
(a) | FitzPatrick net benefit costs are included for the period after acquisition. |
| |
(b) | PHI net periodic benefit costs for the period prior to the merger are not included in the table above. |
| |
(c) | 2016 amount includes an additional termination benefit for PHI. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | |
| | Predecessor |
| | Pension Benefits | | Other
Postretirement Benefits |
| PHI | January 1, 2016 to March 23, 2016 | | January 1, 2016 to March 23, 2016 |
| Components of net periodic benefit cost: | | | |
| Service cost | $ | 12 |
| | $ | 1 |
|
| Interest cost | 26 |
| | 6 |
|
| Expected return on assets | (30 | ) | | (5 | ) |
| Amortization of: | | | |
| Prior service cost (credit) | — |
| | (3 | ) |
| Actuarial loss | 14 |
| | 2 |
|
| Net periodic benefit cost | $ | 22 |
| | $ | 1 |
|
Components of AOCI and Regulatory Assets
Under the authoritative guidance for regulatory accounting, a portion of current year actuarial gains and(gains) losses and prior service costs (credits) is capitalized within Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets (liabilities) for Exelon for the years ended December 31, 2018, 20172020, 2019, and 20162018 for all plans combined and the componentscombined.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| Exelon | 2018 | | 2017 | | 2016(a) | | 2018 | | 2017 | | 2016(a) |
| Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities): | | | | | | | | | | | |
| Current year actuarial (gain) loss | $ | 635 |
| | $ | (222 | ) | | $ | 644 |
| | $ | (232 | ) | | $ | 166 |
| | $ | (101 | ) |
| Amortization of actuarial loss | (629 | ) | | (607 | ) | | (554 | ) | | (66 | ) | | (61 | ) | | (63 | ) |
| Current year prior service cost (credit) | (4 | ) | | 9 |
| | (60 | ) | | — |
| | — |
| | — |
|
| Amortization of prior service (cost) credit | (2 | ) | | (1 | ) | | (14 | ) | | 186 |
| | 188 |
| | 185 |
|
| Settlements | (3 | ) | | (3 | ) | | — |
| | — |
| | — |
| | — |
|
| Acquisitions | — |
| | — |
| | 994 |
| | — |
| | — |
| | 94 |
|
| Total recognized in AOCI and regulatory assets (liabilities) | $ | (3 | ) |
| $ | (824 | ) | | $ | 1,010 |
| | $ | (112 | ) |
| $ | 293 |
| | $ | 115 |
|
| | | | | | | | | | | | |
| Total recognized in AOCI | $ | 3 |
| | $ | (401 | ) | | $ | 51 |
| | $ | (55 | ) | | $ | 168 |
| | $ | 20 |
|
| Total recognized in regulatory assets (liabilities) | $ | (6 | ) | | $ | (423 | ) | | $ | 959 |
| | $ | (57 | ) | | $ | 125 |
| | $ | 95 |
|
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
| | | | | | | | Pension Benefits | | OPEB |
| | Predecessor | | 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 |
| | Pension Benefits | | Other
Postretirement Benefits | |
| PHI | January 1, 2016 to March 23, 2016 | | January 1, 2016 to March 23, 2016 | |
Changes in plan assets and benefit
obligations recognized in AOCI and regulatory assets (liabilities): | | | | Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities): | | | | | | | | | | | |
| Current year actuarial loss (gain) | $ | — |
| | $ | — |
| Current year actuarial loss (gain) | $ | 941 | | | $ | 538 | | | $ | 635 | | | $ | 22 | | | $ | 80 | | | $ | (232) | |
| Amortization of actuarial loss | (14 | ) | | (2 | ) | Amortization of actuarial loss | (512) | | | (414) | | | (629) | | | (49) | | | (45) | | | (66) | |
| Current year prior service cost (credit) | | Current year prior service cost (credit) | 0 | | | 68 | | | (4) | | | (111) | | | 0 | | | 0 | |
| Amortization of prior service (cost) credit | — |
| | 3 |
| Amortization of prior service (cost) credit | (4) | | | 0 | | | (2) | | | 124 | | | 179 | | | 186 | |
| | Curtailments | | Curtailments | 0 | | | (3) | | | 0 | | | 1 | | | 0 | | | 0 | |
| Settlements | | Settlements | (14) | | | (17) | | | (3) | | | (1) | | | (1) | | | 0 | |
| | Total recognized in AOCI and regulatory assets (liabilities) | $ | (14 | ) | | $ | 1 |
| Total recognized in AOCI and regulatory assets (liabilities) | $ | 411 | | | $ | 172 | | | $ | (3) | | | $ | (14) | | | $ | 213 | | | $ | (112) | |
| | | | | | | | | | | | | | | | |
| Total recognized in AOCI | $ | (1 | ) | | $ | — |
| Total recognized in AOCI | $ | 271 | | | $ | 169 | | | $ | 3 | | | $ | 6 | | | $ | 107 | | | $ | (55) | |
| Total recognized in regulatory assets (liabilities) | $ | (13 | ) | | $ | 1 |
| Total recognized in regulatory assets (liabilities) | $ | 140 | | | $ | 3 | | | $ | (6) | | | $ | (20) | | | $ | 106 | | | $ | (57) | |
__________
| |
(a) | 2016 amounts include PHI for the period of March 24, 2016 through December 31, 2016. |
The following table provides the components of gross accumulated other comprehensive loss and regulatory assets (liabilities) for Exelon that have not been recognized as components of periodic benefit cost at December 31, 20182020 and 2017,2019, respectively, for all plans combined:
| | | | Exelon | | Exelon | |
| | Pension Benefits | | | Other Postretirement Benefits | | Pension Benefits | | | OPEB | |
| | 2018 | | 2017 | | 2018 | | 2017 | | 2020 | | 2019 | | | 2020 | | 2019 | |
| Prior service (credit) cost | $ | (29 | ) |
| $ | (24 | ) | | $ | (337 | ) | | $ | (522 | ) | |
| Prior service cost (credit) | | Prior service cost (credit) | $ | 35 | | | $ | 39 | | | | $ | (145) | | | $ | (158) | | |
| Actuarial loss | 7,558 |
| | 7,556 |
| | 531 |
| | 829 |
| Actuarial loss | 8,077 | | | 7,662 | | | | 538 | | | 565 | | |
| Total | $ | 7,529 |
| | $ | 7,532 |
| | $ | 194 |
| | $ | 307 |
| Total | $ | 8,112 | | | $ | 7,701 | | | | $ | 393 | | | $ | 407 | | |
| | | | | | | | | | | | | | | | | | |
| Total included in AOCI | $ | 3,899 |
| | $ | 3,896 |
| | $ | 70 |
| | $ | 125 |
| Total included in AOCI | $ | 4,339 | | | $ | 4,068 | | | | $ | 183 | | | $ | 177 | | |
| Total included in regulatory assets (liabilities) | $ | 3,630 |
| | $ | 3,636 |
| | $ | 124 |
| | $ | 182 |
| Total included in regulatory assets (liabilities) | $ | 3,773 | | | $ | 3,633 | | | | $ | 210 | | | $ | 230 | | |
Average Remaining Service Period
For pension benefits, Exelon amortizes its unrecognized prior service costs (credits) and certain actuarial gains and(gains) losses, as applicable, based on participants’ average remaining service periods. The average remaining service period of Exelon's defined benefit pension plan participants was 12.0 years, 11.8 years and 11.9 years for the years ended December 31, 2018, 2017 and 2016, respectively.
For other postretirement benefits,OPEB, Exelon amortizes its unrecognized prior service costs (credits) over participants’ average remaining service period to benefit eligibility age and amortizes certain actuarial gains and(gains) losses over participants’ average remaining service period to expected retirement. The resulting average remaining service periodperiods for pension and OPEB were as follows:
| | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| Pension plans | | 12.3 | | | 11.7 | | | 12.0 | |
| OPEB plans: | | | | | | |
| Benefit Eligibility Age | | 9.0 | | | 8.7 | | | 8.8 | |
| Expected Retirement | | 10.2 | | | 9.3 | | | 9.5 | |
Assumptions
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Assumptions
The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and other postretirementOPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, including the discount rate applied to benefit obligations, the long-term EROA, Exelon’s expected level of contributions to the plans, the long-term expected investment rate credited to employees participating in cash balance plans and the anticipated rate of increase of health care costs. Additionally, assumptions related to plan participants include the incidence of mortality, the expected remaining service period, the level of compensation and rate of compensation increases, employee age and length of service,as shown below, among other factors. When developing the required assumptions, Exelon considers historical information as well as future expectations.
Expected Rate of Return. In selectingdetermining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.
Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. For the year endedDecember 31, 2020, Exelon’s mortality assumption is supported by an actuarial experience study of Exelon's plan participants and utilizes the IRS's RP–2000SOA 2019 base table projected to 2012 with(Pri-2012) and MP-2020 improvement scale AAadjusted to use Proxy SSA ultimate improvement rates. For the year ended December 31, 2019, Exelon's mortality assumption utilizes the SOA 2019 base table (Pri-2012) and projected thereafter with generationalMP-2019 improvement scale BB two-dimensional adjusted to a 0.75% long-term rate reached in 2027. There were no changes to2035.
For Exelon, the mortality assumption in 2016, 2017 or 2018.
The following assumptions were used to determine the benefit obligations for the plans at December 31, 2018, 20172020 and 2016.2019. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.
| | | | | | | | | | | | | | | | | | | | | Pension Benefits | | OPEB | |
| | Pension Benefits | | Other Postretirement Benefits | | | 2020 | | 2019 | | 2020 | | 2019 | |
| Exelon | 2018 | | 2017 | | 2016(f) | | 2018 | | 2017 | | 2016(f) | | |
| Discount rate | 4.31 | % | (a) | 3.62 | % | (b) | 4.04 | % | (c) | 4.30 | % | (a) | 3.61 | % | (b) | 4.04 | % | (c) | Discount rate | 2.58 | % | (a) | 3.34 | % | (a) | 2.51 | % | (a) | 3.31 | % | (a) |
| Investment Crediting Rate | 4.46 | % | | 4.00 | % | | 4.46 | % | | N/A | | N/A | | N/A |
| | |
| Investment crediting rate | | Investment crediting rate | 3.72 | % | (b) | 3.82 | % | (b) | N/A | | N/A | |
| Rate of compensation increase | | (d) | | (d) | | (e) | | (d) | | (d) | | (e) | Rate of compensation increase | 3.75 | % | | | (c) | 3.75 | % | | | (c) |
| Mortality table | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | Mortality table | Pri-2012 table with MP- 2020 improvement scale (adjusted) | | Pri-2012 table with MP- 2019 improvement scale (adjusted) | | Pri-2012 table with MP- 2020 improvement scale (adjusted) | | Pri-2012 table with MP- 2019 improvement scale (adjusted) | |
| Health care cost trend on covered charges | N/A | | N/A | | N/A | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.00% with
ultimate
trend of
5.00% in
2017 | | 5.00%
decreasing
to
ultimate
trend of
5.00% in
2017 | | Health care cost trend on covered charges | N/A | | N/A | | Initial and ultimate rate of 5.00% | | 5.00% with ultimate trend of 5.00% in 2017 | |
__________
| |
(a) | The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of December 31, 2018. Certain benefit plans used individual rates ranging from 4.13% - 4.36% and 4.27% - 4.38% for pension and other postretirement plans, respectively. |
| |
(b) | The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of December 31, 2017. Certain benefit plans used individual rates ranging from 3.49% - 3.65% and 3.57% - 3.68% for pension and other postretirement plans, respectively. |
| |
(c) | The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of December 31, 2016. Certain benefit plans used individual rates ranging from 3.66% - 4.11% and 4.00% - 4.17% for pension and other postretirement plans, respectively. |
| |
(d) | 3.25% through 2019 and 3.75% thereafter. |
(a)The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and OPEB obligations. Certain benefit plans used individual rates, which range from 2.11% - 2.73% and 2.45% - 2.63% for pension and OPEB plans, respectively, as of December 31, 2020 and 3.02% - 3.44% and 3.27% - 3.40% for pension and OPEB plans, respectively, as of December 31, 2019.
(b)The investment crediting rate above represents a weighted average rate.
(c)3.25% through 2019 and 3.75% thereafter.
The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2020, 2019 and 2018:
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
| |
(e) | The legacy Exelon, CEG and CENG pension and other postretirement plans used a rate of compensation increase of 3.25% through 2019 and 3.75% thereafter, while the legacy PHI pension and other postretirement plans used a weighted-average rate of compensation increase of 5% for all periods. |
| |
(f) | Obligation was not remeasured for the PHI predecessor for the period from January 1, 2016, to March 23, 2016. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB | |
| 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 | |
| Discount rate | 3.34 | % | (a) | 4.31 | % | (a) | 3.62 | % | (a) | 3.31 | % | (a) | 4.30 | % | (a) | 3.61 | % | (a) |
| Investment crediting rate | 3.82 | % | (b) | 4.46 | % | (b) | 4.00 | % | (b) | N/A | | N/A | | N/A | |
| Expected return on plan assets | 7.00 | % | (c) | 7.00 | % | (c) | 7.00 | % | (c) | 6.69 | % | (c) | 6.67 | % | (c) | 6.60 | % | (c) |
| Rate of compensation increase | | (d) | | (d) | | (d) | | (d) | | (d) | | (d) |
| Mortality table | Pri-2012 table with MP- 2019 improvement scale (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | Pri-2012 table with MP- 2019 improvement scale (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) | |
| Health care cost trend on covered charges | N/A | | N/A | | N/A | | Initial and ultimate rate of 5.00% | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.00% with ultimate trend of 5.00% in 2017 | |
__________
(a)The following assumptions werediscount rates above represent the blended rates used to determineestablish the net periodicmajority of Exelon’s pension and OPEB costs. Certain benefit costsplans used individual rates, which range from 3.02%-3.44% and 3.27%-3.40% for pension and OPEB plans, respectively, for the plans for the yearsyear ended December 31, 2018, 20172020; 4.13%-4.36% and 2016, as well as4.27%-4.38% for pension and OPEB plans; respectively, for the PHI predecessor period January 1, 2016year ended December 31, 2019; and 3.49%-3.65% and 3.57%-3.68% for pension and OPEB plans, respectively, for the year ended December 31, 2018.
(b)The investment crediting rate above represents a weighted average rate.
(c)Not applicable to March 23, 2016: pension and OPEB plans that do not have plan assets.
(d)3.25% through 2019 and 3.75% thereafter.
|
| | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits | |
| Exelon | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | |
| Discount rate | 3.62 | % | (a) | 4.04 | % | (b) | 4.29 | % | (c) | 3.61 | % | (a) | 4.04 | % | (b) | 4.29 | % | (c) |
| Investment Crediting Rate | 4.00 | % | | 4.46 | % | | 5.31 | % | | N/A |
| | N/A |
| | N/A |
| |
| Expected return on plan assets | 7.00 | % | (d) | 7.00 | % | (d) | 7.00 | % | (d) | 6.60 | % | (d) | 6.58 | % | (d) | 6.71 | % | (d) |
| Rate of compensation increase | |
|
(e)
| |
(f) | | (f) | |
|
(e) | |
(f)
| |
(f)
|
| Mortality table | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| |
| Health care cost trend on covered charges | N/A | | N/A | | N/A | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.00%
with
ultimate
trend of
5.00% in
2017 | | 5.50%
decreasing
to
ultimate
trend of
5.00% in
2017 | |
|
| | | | | |
| | Predecessor |
| | Pension Benefits | | Other Postretirement Benefits |
| PHI | January 1, 2016 to March 23, 2016 | | January 1, 2016 to March 23, 2016 |
| Discount rate | 4.65%/4.55% |
| (g) | 4.55 | % |
| Investment crediting rate | 2.89 | % | | N/A |
|
Expected return on plan assets(h) | 6.50 | % | | 6.75 | % |
Rate of compensation
increase | 5.00 | % | | 5.00 | % |
| Mortality table | RP-2014 table with improvement scale MP-2015 | | RP-2014 table with improvement scale MP-2015 |
| Health care cost trend on covered charges | N/A | | 6.33% pre-65 and 5.40% post-65 decreasing to ultimate trend of 5.00% in 2020 |
__________
| |
(a) | The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2018. Certain benefit plans used individual rates ranging from 3.49%-3.65% and 3.57%-3.68% for pension and other postretirement plans, respectively. |
| |
(b) | The discount rates above represent the blended rates used to establish the majority of Exelon's pension and other postretirement benefits costs for the year ended December 31, 2017. Certain benefit plans used individual rates ranging from 3.66%-4.11% and 4.00%-4.17% for pension and other postretirement plans, respectively. |
| |
(c) | The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2016. Certain benefit plans used the individual rates ranging from 3.68%-4.14% and 4.32%-4.43% for pension and other postretirement plans, respectively. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(d) | Not applicable to pension and other postretirement benefit plans that do not have plan assets. |
| |
(e) | 3.25% through 2019 and 3.75% thereafter. |
| |
(f) | The legacy Exelon, CEG and CENG pension and other postretirement plans used a rate of compensation increase of 3.25% through 2019 and 3.75% thereafter, while the legacy PHI pension and other postretirement plans used a weighted-average rate of compensation increase of 5% for all periods. |
| |
(g) | The discount rate for the qualified and non-qualified pension plans was 4.65% and 4.55%, respectively. |
| |
(h) | Expected return on other postretirement benefit plan assets is pre-tax. |
Contributions
Exelon allocates contributions related to its legacy Exelon pension and OPEB plans to its subsidiaries based on accounting cost. For legacy CEG, CENG, FitzPatrick, and PHI plans, pension and OPEB contributions are allocated to the subsidiaries based on employee participation (both active and retired). The following tables provide contributions to the pension and other postretirement benefitOPEB plans:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | OPEB | |
| | 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 | |
| Exelon | $ | 542 | | | $ | 356 | | | $ | 337 | | | $ | 59 | | | $ | 51 | | | $ | 46 | | |
| Generation | 236 | | | 160 | | | 128 | | | 19 | | | 15 | | | 11 | | |
| ComEd | 143 | | | 72 | | | 38 | | | 5 | | | 5 | | | 4 | | |
| PECO | 18 | | | 27 | | | 28 | | | 0 | | | 1 | | | 0 | | |
| BGE | 56 | | | 34 | | | 40 | | | 22 | | | 14 | | | 14 | | |
| PHI | 30 | | | 10 | | | 62 | | | 9 | | | 15 | | | 12 | | |
| Pepco | 2 | | | 2 | | | 6 | | | 9 | | | 12 | | | 11 | | |
| DPL | 0 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | |
| ACE | 2 | | | 0 | | | 6 | | | 0 | | | 1 | | | 0 | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2018(a) | | 2017(a) | | 2016(a) | | 2018 | | 2017 | | 2016 |
| Exelon | $ | 337 |
|
| $ | 341 |
|
| $ | 347 |
|
| $ | 46 |
|
| $ | 64 |
|
| $ | 50 |
|
| Generation | 128 |
| | 137 |
| | 140 |
| | 11 |
| | 11 |
| | 12 |
|
| ComEd | 38 |
| | 36 |
| | 33 |
| | 4 |
| | 5 |
| | 5 |
|
| PECO | 28 |
| | 24 |
| | 30 |
| | — |
| | — |
| | — |
|
| BGE | 40 |
| | 39 |
| | 31 |
| | 14 |
| | 14 |
| | 18 |
|
BSC(b) | 41 |
| | 38 |
| | 39 |
| | 5 |
| | 2 |
| | 3 |
|
| Pepco | 6 |
| | 62 |
| | 24 |
| | 11 |
| | 10 |
| | 8 |
|
| DPL | — |
| | — |
| | 22 |
| | — |
| | 2 |
| | — |
|
| ACE | 6 |
| | — |
| | 15 |
| | — |
| | 20 |
| | 2 |
|
PHISCO (c) | 50 |
| | 5 |
| | 17 |
| | 1 |
| | — |
| | 2 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| | 2018 | | 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | 2018 | | 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| PHI | $ | 62 |
| | $ | 67 |
| | $ | 74 |
| | | $ | 4 |
| | $ | 12 |
| | $ | 32 |
| | $ | 12 |
| | | $ | — |
|
__________
| |
(a) | Exelon's and Generation's pension contributions include $21 million and $25 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG for the years ended December 31, 2017 and 2016, respectively. There were no pension contributions for the year ended December 31, 2018. |
| |
(b) | Includes $2 million, $4 million, and $6 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2018, 2017, and 2016, respectively. |
| |
(c) | PHISCO’s pension contributions for the year ended December 31, 2016 include $4 million of contributions made prior to the closing of Exelon’s merger with PHI on March 23, 2016. |
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of contributing the greater of (1) $300 million until all the qualified plans are fullyachieving 100% funded status on an ABO basis and (2) the minimum amounts under ERISA to meet minimum contribution requirement and/or avoid benefit restrictions and at-risk status.over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change,
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Exelon’s estimated annual qualified pension contributions will be approximately $500 million in 2021. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.
While other postretirementOPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however,
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon’s management has historically considered several factors in determining the level of contributions to its other postretirement benefitOPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.
The following table provides all registrants'Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to other postretirementOPEB plans in 2019:2021:
| |
| Qualified Pension Plans |
| Non-Qualified Pension Plans |
| Other
Postretirement
Benefits | | Qualified Pension Plans | | Non-Qualified Pension Plans | | OPEB |
| Exelon | $ | 301 |
|
| $ | 25 |
|
| $ | 44 |
| Exelon | $ | 505 | | | $ | 51 | | | $ | 75 | |
| Generation | 135 |
|
| 7 |
|
| 13 |
| Generation | 196 | | | 27 | | | 24 | |
| ComEd | 65 |
|
| 1 |
|
| 2 |
| ComEd | 170 | | | 2 | | | 23 | |
| PECO | 25 |
|
| 1 |
|
| — |
| PECO | 14 | | | 1 | | | 0 | |
| BGE | 34 |
|
| 1 |
|
| 15 |
| BGE | 57 | | | 1 | | | 16 | |
| BSC | 41 |
|
| 7 |
|
| 2 |
| |
| PHI | 1 |
|
| 8 |
|
| 12 |
| PHI | 29 | | | 9 | | | 7 | |
| Pepco | — |
|
| 2 |
|
| 10 |
| Pepco | 1 | | | 2 | | | 6 | |
| DPL | — |
|
| 1 |
|
| — |
| DPL | 0 | | | 1 | | | 0 | |
| ACE | — |
|
| — |
|
| 1 |
| ACE | 3 | | | 0 | | | 0 | |
| PHISCO | 1 |
|
| 5 |
|
| 1 |
| |
Estimated Future Benefit Payments
Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 20182020 were:
| | | | | | | | | | | |
| Pension
Benefits | | OPEB |
| 2021 | $ | 1,279 | | | $ | 257 | |
| 2022 | 1,280 | | | 259 | |
| 2023 | 1,315 | | | 261 | |
| 2024 | 1,325 | | | 262 | |
| 2025 | 1,338 | | | 265 | |
| 2026 through 2030 | 6,759 | | | 1,320 | |
| Total estimated future benefit payments through 2030 | $ | 13,296 | | | $ | 2,624 | |
|
| | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| 2019 | $ | 1,196 |
| | $ | 255 |
|
| 2020 | 1,221 |
| | 263 |
|
| 2021 | 1,258 |
| | 269 |
|
| 2022 | 1,284 |
| | 274 |
|
| 2023 | 1,302 |
| | 282 |
|
| 2024 through 2028 | 6,770 |
| | 1,483 |
|
| Total estimated future benefit payments through 2028 | $ | 13,031 |
|
| $ | 2,826 |
|
Allocation to Exelon Subsidiaries
All registrants account for their participation in Exelon’s pension and other postretirement benefit plans by applying multi-employer accounting. Employee-related assets and liabilities, including both pension and postretirement liabilities, for the legacy Exelon plans were allocated by Exelon to its subsidiaries based on the number of active employees as of January 1, 2001 as part of Exelon’s corporate restructuring. The obligation for Generation, ComEd and PECO reflects the initial allocation and the cumulative costs incurred and contributions made since January 1, 2001. Historically, Exelon has allocated the components of pension and other postretirement costs to the subsidiaries in the legacy Exelon plans based upon several factors, including the measures of active employee participation in each plan. Pension and other postretirement benefit contributions were allocated to legacy Exelon subsidiaries in proportion to active service costs recognized and total costs recognized, respectively. Beginning in 2015, Exelon began allocating costs related to its legacy Exelon pension and other postretirement benefit plans to its subsidiaries based on both active and retired employee participation and contributions are allocated based on accounting cost. The impact of this allocation methodology change was not material to any Registrant. For legacy CEG, legacy
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
CENG, FitzPatrick, and legacy PHI plans, components of pension and other postretirement benefit costs and contributions have been, and will continue to be, allocated to the subsidiaries based on employee participation (both active and retired).
The amounts below represent the Registrants’ as well as BSC's and PHISCO's pension and OPEB costs. As a result of new pension guidance effective on January 1, 2018, certain balances have been reclassified on Exelon’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2017 and 2016. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment, net, for the years ended December 31, 2018, 2017 and 2016, while the non–service cost components are included in Other, net and Regulatory assets for year ended December 31, 2018 and in Other, net and Property, plant and equipment, net, for the years ended December 31, 2017 and 2016. For Generation and the Utility Registrants, the service cost and non–service cost components are included in Operating and maintenance expense and Property, plant and equipment, net on their consolidated financial statements for the years ended December 31, 2018, 2017 and 2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | Exelon | | Generation(a) | | ComEd | | PECO | | BGE | | BSC(b) | | Pepco(c) | | DPL(c) | | ACE(c) | | PHISCO(c)(d) |
| 2018 | $ | 583 |
| | $ | 204 |
|
| $ | 177 |
|
| $ | 18 |
| | $ | 60 |
| | $ | 57 |
| | $ | 15 |
| | $ | 6 |
| | $ | 12 |
| | $ | 34 |
|
| 2017 | 643 |
| | 227 |
|
| 176 |
|
| 29 |
| | 64 |
| | 53 |
| | 25 |
| | 13 |
| | 13 |
| | 43 |
|
| 2016 | 621 |
| | 218 |
|
| 166 |
|
| 33 |
| | 68 |
| | 48 |
| | 31 |
| | 18 |
| | 15 |
| | 47 |
|
|
| | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| PHI | For the Year Ended December 31, 2018 | | For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Pension and Other Postretirement Benefit Costs | $ | 67 |
| | $ | 94 |
| | $ | 88 |
| | | $ | 23 |
|
__________
| |
(a) | FitzPatrick net benefit costs are included for the period after acquisition. |
| |
(b) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above. |
| |
(c) | Pepco's, DPL's, ACE's and PHISCO's pension and postretirement benefit costs for the year ended December 31, 2016 include $7 million, $4 million, $3 million and $9 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016. |
| |
(d) | These amounts represent amounts billed to Pepco, DPL and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts above. |
Plan Assets
Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.
Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon’s other postretirementOPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.
Actual asset returns have an impact on the costs reported for the Exelon-sponsored pension and other postretirement benefitOPEB plans. The actual asset returns across Exelon’s pension and other postretirement benefitOPEB plans for the year ended December 31, 20182020 were (4.86)%14.45% and (4.66)%9.14%, respectively, compared to an expected long-term return assumption of 7.00% and 6.60%6.69%, respectively.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
respectively. Exelon used an EROA of 7.00% and 6.46% to estimate its 2021 pension and OPEB costs, respectively.
Exelon’s pension and other postretirement benefitOPEB plan target asset allocations at December 31, 20182020 and 2017 asset allocations2019 were as follows:
Pension Plans | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Asset Category | Pension Benefits | | OPEB | | Pension Benefits | | OPEB |
| Equity securities | 34 | % | | 45 | % | | 33 | % | | 46 | % |
| Fixed income securities | 43 | % | | 39 | % | | 44 | % | | 32 | % |
Alternative investments(a) | 23 | % | | 16 | % | | 23 | % | | 22 | % |
| Total | 100 | % | | 100 | % | | 100 | % | | 100 | % |
|
| | | | | | | | |
| | | | Exelon |
| | | | Percentage of Plan Assets at December 31, |
| Asset Category | Target Allocation | | 2018 | | 2017 |
| Equity securities | 35 | % | | 32 | % | | 35 | % |
| Fixed income securities | 37 | % | | 38 |
| | 39 |
|
Alternative investments(a) | 28 | % | | 30 |
| | 26 |
|
| Total | | | 100 | % | | 100 | % |
Other Postretirement Benefit Plans
|
| | | | | | | | |
| | | | Exelon |
| | | | Percentage of Plan Assets at December 31, |
| Asset Category | Target Allocation | | 2018 | | 2017 |
| Equity securities | 47 | % | | 44 | % | | 47 | % |
| Fixed income securities | 28 | % | | 28 |
| | 28 |
|
Alternative investments(a) | 25 | % | | 28 |
| | 25 |
|
| Total | | | 100 | % | | 100 | % |
__________ | |
(a) | Alternative investments include private equity, hedge funds, real estate, and private credit. |
Concentrations of Credit Risk. Exelon evaluated its pension and other postretirement benefitOPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2018.2020. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2018,2020, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and other postretirement benefitOPEB plan assets.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Fair Value Measurements
The following tables present pension and other postretirement benefitOPEB plan assets measured and recorded at fair value in Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Pension plan assets(a) | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | $ | 408 | | | $ | 121 | | | $ | 0 | | | $ | 0 | | | $ | 529 | | | $ | 258 | | | $ | 107 | | | $ | 0 | | | $ | 0 | | | $ | 365 | |
| | | | | | | | | | | | | | | | | | | |
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Equities(b) | 4,255 | | | 0 | | | 2 | | | 2,552 | | | 6,809 | | | 3,616 | | | 1 | | | 5 | | | 2,589 | | | 6,211 | |
| Fixed income: | | | | | | | | | | | | | | | | | | | |
| U.S. Treasury and agencies | 1,137 | | | 367 | | | 0 | | | 0 | | | 1,504 | | | 1,294 | | | 280 | | | 0 | | | 0 | | | 1,574 | |
| State and municipal debt | 0 | | | 85 | | | 0 | | | 0 | | | 85 | | | 0 | | | 56 | | | 0 | | | 0 | | | 56 | |
Corporate debt(c) | 0 | | | 4,873 | | | 573 | | | 0 | | | 5,446 | | | 0 | | | 4,390 | | | 245 | | | 0 | | | 4,635 | |
Other(b) | 0 | | | 239 | | | 21 | | | 537 | | | 797 | | | 0 | | | 305 | | | 0 | | | 851 | | | 1,156 | |
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| Fixed income subtotal | 1,137 | | | 5,564 | | | 594 | | | 537 | | | 7,832 | | | 1,294 | | | 5,031 | | | 245 | | | 851 | | | 7,421 | |
| Private equity | 0 | | | 0 | | | 0 | | | 1,632 | | | 1,632 | | | 0 | | | 0 | | | 0 | | | 1,391 | | | 1,391 | |
| Hedge funds | 0 | | | 0 | | | 0 | | | 1,314 | | | 1,314 | | | 0 | | | 0 | | | 0 | | | 1,126 | | | 1,126 | |
| | | | | | | | | | | | | | | | | | | |
| Real estate | 0 | | | 0 | | | 0 | | | 1,080 | | | 1,080 | | | 0 | | | 0 | | | 0 | | | 1,030 | | | 1,030 | |
| Private credit | 0 | | | 0 | | | 234 | | | 1,046 | | | 1,280 | | | 0 | | | 0 | | | 237 | | | 929 | | | 1,166 | |
| Pension plan assets subtotal | 5,800 | | | 5,685 | | | 830 | | | 8,161 | | | 20,476 | | | 5,168 | | | 5,139 | | | 487 | | | 7,916 | | | 18,710 | |
| | | | | | | | | | | | | | | | | | | |
OPEB plan assets(a) | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 50 | | | 52 | | | 0 | | | 0 | | | 102 | | | 39 | | | 49 | | | 0 | | | 0 | | | 88 | |
| Equities | 618 | | | 2 | | | 0 | | | 569 | | | 1,189 | | | 473 | | | 5 | | | 0 | | | 719 | | | 1,197 | |
| Fixed income: | | | | | | | | | | | | | | | | | | | |
| U.S. Treasury and agencies | 16 | | | 66 | | | 0 | | | 0 | | | 82 | | | 17 | | | 64 | | | 0 | | | 0 | | | 81 | |
| State and municipal debt | 0 | | | 89 | | | 0 | | | 0 | | | 89 | | | 0 | | | 107 | | | 0 | | | 0 | | | 107 | |
Corporate debt(c) | 0 | | | 89 | | | 0 | | | 0 | | | 89 | | | 0 | | | 71 | | | 0 | | | 0 | | | 71 | |
| Other | 285 | | | 3 | | | 0 | | | 179 | | | 467 | | | 258 | | | 5 | | | 0 | | | 201 | | | 464 | |
| Fixed income subtotal | 301 | | | 247 | | | 0 | | | 179 | | | 727 | | | 275 | | | 247 | | | 0 | | | 201 | | | 723 | |
| | | | | | | | | | | | | | | | | | | |
| Hedge funds | 0 | | | 0 | | | 0 | | | 308 | | | 308 | | | 0 | | | 0 | | | 0 | | | 293 | | | 293 | |
| Real estate | 0 | | | 0 | | | 0 | | | 111 | | | 111 | | | 0 | | | 0 | | | 0 | | | 109 | | | 109 | |
| Private credit | 0 | | | 0 | | | 0 | | | 117 | | | 117 | | | 0 | | | 0 | | | 0 | | | 131 | | | 131 | |
| OPEB plan assets subtotal | 969 | | | 301 | | | 0 | | | 1,284 | | | 2,554 | | | 787 | | | 301 | | | 0 | | | 1,453 | | | 2,541 | |
Total pension and OPEB plan assets(d) | $ | 6,769 | | | $ | 5,986 | | | $ | 830 | | | $ | 9,445 | | | $ | 23,030 | | | $ | 5,955 | | | $ | 5,440 | | | $ | 487 | | | $ | 9,369 | | | $ | 21,251 | |
__________
(a)See Note 18—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.
(b)Includes derivative instruments of $2 million for the years ended December 31, 2020 and 2019, which have total notional amounts of $6,879 million and $6,668 million at December 31, 2020 and 2019, respectively. The notional principal
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.
(c)Includes investments in equities sold short held in investment vehicles primarily to hedge the equity option component of its convertible debt. Pension equities sold short totaled $(96) million and $(75) million as of December 31, 2020 and 2019, respectively. OPEB equities sold short totaled $(42) million and $(35) million as of December 31, 2020 and 2019, respectively.
(d)Excludes net liabilities of $132 million and $120 million at December 31, 2020 and 2019, respectively, which include certain derivative assets that have notional amounts of $239 million and $632 million at December 31, 2020 and 2019, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases and interest and dividends receivable.
The following table presents the reconciliation of Level 3 assets and liabilities for Exelon measured at fair value for pension and OPEB plans for the years ended December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Fixed Income | | Equities | | Private
Credit | | Total |
| Pension Assets | | | | | | | | | | | | | |
| Balance as of January 1, 2020 | | | | | | | $ | 245 | | | $ | 5 | | | $ | 237 | | | $ | 487 | |
| Actual return on plan assets: | | | | | | | | | | | | | |
Relating to assets still held at the
reporting date | | | | | | | 19 | | | (3) | | | 15 | | | 31 | |
| | | | | | | | | | | | | |
| Purchases, sales and settlements: | | | | | | | | | | | | | |
| Purchases | | | | | | | 34 | | | 0 | | | 24 | | | 58 | |
| | | | | | | | | | | | | |
Settlements(a) | | | | | | | (3) | | | 0 | | | (42) | | | (45) | |
Transfers into Level 3(b) | | | | | | | 299 | | | 0 | | | 0 | | | 299 | |
| Balance as of December 31, 2020 | | | | | | | $ | 594 | | | $ | 2 | | | $ | 234 | | | $ | 830 | |
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| | | | | | | Fixed Income | | Equities | | Private
Credit | | Total |
| Pension Assets | | | | | | | | | | | | | |
| Balance as of January 1, 2019 | | | | | | | $ | 216 | | | $ | 2 | | | $ | 268 | | | $ | 486 | |
| Actual return on plan assets: | | | | | | | | | | | | | |
Relating to assets still held at the reporting date | | | | | | | 28 | | | 3 | | | 28 | | | 59 | |
Relating to assets sold during the period | | | | | | | (7) | | | 0 | | | 0 | | | (7) | |
| Purchases, sales and settlements: | | | | | | | | | | | | | |
| Purchases | | | | | | | 26 | | | 0 | | | 41 | | | 67 | |
| Sales | | | | | | | (4) | | | 0 | | | 0 | | | (4) | |
Settlements(a) | | | | | | | (2) | | | 0 | | | (100) | | | (102) | |
| Transfers out of Level 3 | | | | | | | (12) | | | 0 | | | 0 | | | (12) | |
| Balance as of December 31, 2019 | | | | | | | $ | 245 | | | $ | 5 | | | $ | 237 | | | $ | 487 | |
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__________
(a)Represents cash settlements only.
(b)In 2020, a contract was terminated for a certain fixed income commingled fund resulting in the ownership of certain fixed income securities which led to a transfer into Level 3 from not subject to leveling of $299 million.
Valuation Techniques Used to Determine Fair Value
The techniques used to fair value the pension and OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real estate, and private credit investments are the same as the valuation techniques for these types of investments in NDTFs. See Cash Equivalents and NDT Fund Investments in Note 18 - Fair Value of Financial Assets and Liabilities for further information.
Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate.
Defined Contribution Savings Plan (All Registrants)
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2020, 2019, and 2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2020 | $ | 158 | | | $ | 63 | | | $ | 36 | | | $ | 12 | | | $ | 13 | | | 14 | | | $ | 4 | | | $ | 3 | | | $ | 3 | |
| 2019 | 161 | | | 73 | | | 35 | | | 11 | | | 12 | | | 13 | | | 3 | | | 3 | | | 2 | |
| 2018 | 179 | | | 86 | | | 37 | | | 9 | | | 12 | | | 13 | | | 3 | | | 2 | | | 2 | |
16. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange risk related to ongoing business operations.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings at Generation and are offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settles and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.
Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.
Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd are downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
Commodity Price Risk (All Registrants)
Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels, and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.
Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.
Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.
| | | | | | | | | | | |
| Registrant | Commodity | Accounting Treatment | Hedging Instrument |
| ComEd | Electricity | NPNS | Fixed price contracts based on all requirements in the IPA procurement plans. |
| Electricity | Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a) | 20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year. |
PECO(b) | Gas | NPNS | Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales. |
| BGE | Electricity | NPNS | Fixed price contracts for all SOS requirements through full requirements contracts. |
| Gas | NPNS | Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. |
| Pepco | Electricity | NPNS | Fixed price contracts for all SOS requirements through full requirements contracts. |
| DPL | Electricity | NPNS | Fixed price contracts for all SOS requirements through full requirements contracts. |
| Gas | NPNS | Fixed and Index priced contracts through full requirements contracts. |
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(c) | Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections. |
| ACE | Electricity | NPNS | Fixed price contracts for all BGS requirements through full requirements contracts. |
_________
(a)See Note 3—Regulatory Matters for additional information.
(b)As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.
(c)The fair value of the DPL economic hedge is not material as of December 31, 2020 and 2019 and is not presented in the fair value tables below.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of December 31, 2020 and 2019:
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| Exelon | | Generation | | ComEd | | | | | |
| December 31, 2020 | Total
Derivatives | | Economic
Hedges | | Proprietary
Trading | | Collateral (a)(b) | | Netting(a) | | Subtotal | | Economic
Hedges | | | | | | | | | |
| Mark-to-market derivative assets (current assets) | $ | 639 | | | $ | 2,757 | | | $ | 40 | | | $ | 103 | | | $ | (2,261) | | | $ | 639 | | | $ | 0 | | | | | | | | | | |
| Mark-to-market derivative assets (noncurrent assets) | 554 | | | 1,501 | | | 4 | | | 64 | | | (1,015) | | | 554 | | | 0 | | | | | | | | | | |
| Total mark-to-market derivative assets | 1,193 | | | 4,258 | | | 44 | | | 167 | | | (3,276) | | | 1,193 | | | 0 | | | | | | | | | | |
| Mark-to-market derivative liabilities (current liabilities) | (293) | | | (2,629) | | | (23) | | | 131 | | | 2,261 | | | (260) | | | (33) | | | | | | | | | | |
| Mark-to-market derivative liabilities (noncurrent liabilities) | (472) | | | (1,335) | | | (2) | | | 118 | | | 1,015 | | | (204) | | | (268) | | | | | | | | | | |
| Total mark-to-market derivative liabilities | (765) | | | (3,964) | | | (25) | | | 249 | | | 3,276 | | | (464) | | | (301) | | | | | | | | | | |
| Total mark-to-market derivative net assets (liabilities) | $ | 428 | | | $ | 294 | | | $ | 19 | | | $ | 416 | | | $ | 0 | | | $ | 729 | | | $ | (301) | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2019 | | | | | | | | | | | | | | | | | | | | | | |
| Mark-to-market derivative assets (current assets) | $ | 675 | | | $ | 3,506 | | | $ | 72 | | | $ | 287 | | | $ | (3,190) | | | $ | 675 | | | $ | 0 | | | | | | | | | | |
| Mark-to-market derivative assets (noncurrent assets) | 508 | | | 1,238 | | | 25 | | | 122 | | | (877) | | | 508 | | | 0 | | | | | | | | | | |
| Total mark-to-market derivative assets | 1,183 | | | 4,744 | | | 97 | | | 409 | | | (4,067) | | | 1,183 | | | 0 | | | | | | | | | | |
| Mark-to-market derivative liabilities (current liabilities) | (236) | | | (3,713) | | | (38) | | | 357 | | | 3,190 | | | (204) | | | (32) | | | | | | | | | | |
| Mark-to-market derivative liabilities (noncurrent liabilities) | (380) | | | (1,140) | | | (11) | | | 163 | | | 877 | | | (111) | | | (269) | | | | | | | | | | |
| Total mark-to-market derivative liabilities | (616) | | | (4,853) | | | (49) | | | 520 | | | 4,067 | | | (315) | | | (301) | | | | | | | | | | |
| Total mark-to-market derivative net assets (liabilities) | $ | 567 | | | $ | (109) | | | $ | 48 | | | $ | 929 | | | $ | 0 | | | $ | 868 | | | $ | (301) | | | | | | | | | | |
_________
(a)Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit, and other forms of non-cash collateral. These amounts are not material and not reflected in the table above.
(b)Of the collateral posted, $209 million and $511 million represents variation margin on the exchanges at December 31, 2020 and 2019, respectively.
Economic Hedges (Commodity Price Risk)
Generation. For the years ended December 31, 2020, 2019, and 2018, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
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| | Gain (Loss) |
| Income Statement Location | | 2020 | | 2019 | | 2018 |
| | |
| Operating revenues | | $ | 112 | | | $ | 0 | | | $ | (270) | |
| Purchased power and fuel | | 168 | | | (204) | | | (47) | |
| Total Exelon and Generation | | $ | 280 | | | $ | (204) | | | $ | (317) | |
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of December 31, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% for 2021.
Proprietary Trading (Commodity Price Risk)
Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the years ended December 31, 2020, 2019, and 2018, net pre-tax commodity mark-to-market gains and losses for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.
Interest Rate and Foreign Exchange Risk (Exelon and Generation)
Exelon and Generation utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The notional amounts were $516 million and $1,269 million at December 31, 2020 and 2019, respectively, for Exelon and $516 million and $569 million at December 31, 2020 and 2019, respectively, for Generation.
Generation utilizes foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, which are treated as economic hedges. The notional amounts were $149 million and $231 million at December 31, 2020 and 2019, respectively.
The mark-to-market derivative assets and liabilities as of December 31, 2020 and 2019 and the mark-to-market gains and losses for the years ended December 31, 2020, 2019, and 2018 were not material for Exelon and Generation.
Credit Risk (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date.
Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2020. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Rating as of December 31, 2020 | Total
Exposure
Before Credit
Collateral | | Credit Collateral(a) | | Net
Exposure | | Number of
Counterparties
Greater than 10%
of Net Exposure | | Net Exposure of
Counterparties
Greater than 10%
of Net Exposure |
| Investment grade | $ | 577 | | | $ | 27 | | | $ | 550 | | | 0 | | | $ | 0 | |
| Non-investment grade | 32 | | | 0 | | | 32 | | | | | |
| No external ratings | | | | | | | | | |
| Internally rated — investment grade | 165 | | | 1 | | | 164 | | | | | |
| Internally rated — non-investment grade | 80 | | | 28 | | | 52 | | | | | |
| Total | $ | 854 | | | $ | 56 | | | $ | 798 | | | 0 | | | $ | 0 | |
| | | | | |
| Net Credit Exposure by Type of Counterparty | As of December 31, 2020 |
| Financial institutions | $ | 15 | |
| Investor-owned utilities, marketers, power producers | 607 | |
| Energy cooperatives and municipalities | 138 | |
| Other | 38 | |
| Total | $ | 798 | |
__________
(a)As of December 31, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $25 million of letters of credit. The credit collateral does not include non-liquid collateral.
Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of December 31, 2020, the Utility Registrants’ counterparty credit risk with suppliers was not material.
Credit-Risk-Related Contingent Features (All Registrants)
Generation. As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
The aggregate fair value of all derivative instruments with credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:
| | | | | | | | | | | | | | |
| | As of December 31, |
| Credit-Risk Related Contingent Features | | 2020 | | 2019 |
Gross fair value of derivative contracts containing this feature(a) | | $ | (834) | | | $ | (956) | |
Offsetting fair value of in-the-money contracts under master netting arrangements(b) | | 537 | | | 649 | |
Net fair value of derivative contracts containing this feature(c) | | $ | (297) | | | $ | (307) | |
__________
(a)Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements.
(b)Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which Generation could potentially be required to post collateral.
(c)Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
As of December 31, 2020 and 2019, Exelon and Generation posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
| | | | | | | | | | | | | | |
| | As of December 31, |
| | 2020 | | 2019 |
| Cash collateral posted | | $ | 511 | | | $ | 982 | |
| Letters of credit posted | | 226 | | | 264 | |
| Cash collateral held | | 110 | | | 103 | |
| Letters of credit held | | 40 | | | 112 | |
| Additional collateral required in the event of a credit downgrade below investment grade | | 1,432 | | | 1,509 | |
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.
Utility Registrants
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral.
PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of December 31, 2020, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of December 31, 2020, they could have been required to post incremental collateral to their counterparties of $34 million, $54 million, and $9 million, respectively.
17. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and borrowings from the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Commercial Paper
The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Maximum
Program Size at
December 31, | | Outstanding
Commercial
Paper at
December 31, | | Average Interest Rate on
Commercial Paper Borrowings at December 31, |
| Commercial Paper Issuer | 2020(a)(b)(c) | | 2019(a)(b)(c) | | 2020 | | 2019 | | 2020 | | 2019 |
Exelon(d) | $ | 9,000 | | | $ | 9,000 | | | $ | 1,031 | | | $ | 870 | | | 0.25 | % | | 2.25 | % |
| Generation | 5,300 | | | 5,300 | | | 340 | | | 320 | | | 0.27 | % | | 1.84 | % |
| ComEd | 1,000 | | | 1,000 | | | 323 | | | 130 | | | 0.23 | % | | 2.38 | % |
| PECO | 600 | | | 600 | | | 0 | | | 0 | | | 0 | % | | 2.39 | % |
| BGE | 600 | | | 600 | | | 0 | | | 76 | | | 0 | % | | 2.46 | % |
PHI(e) | 900 | | | 900 | | | 368 | | | 208 | | | 0.24 | % | | N/A |
| Pepco | 300 | | | 300 | | | 35 | | | 82 | | | 0.22 | % | | 2.56 | % |
| DPL | 300 | | | 300 | | | 146 | | | 56 | | | 0.24 | % | | 2.02 | % |
| ACE | 300 | | | 300 | | | 187 | | | 70 | | | 0.25 | % | | 2.43 | % |
__________
(a)Excludes $1,500 million and $1,400 million in bilateral credit facilities at December 31, 2020 and 2019, respectively, and $144 million and $159 million in credit facilities for project finance at December 31, 2020 and 2019, respectively. These credit facilities do not back Generation's commercial paper program.
(b)At December 31, 2020, excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $38 million, $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. These facilities expire on October 8, 2021. These facilities are solely utilized to issue letters of credit. At December 31, 2019, excludes $142 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $44 million, $33 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively.
(c)Pepco, DPL, and ACE's revolving credit facility has the ability to flex to $500 million, $500 million, and $350 million, respectively. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL, or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.
(d)Includes revolving credit agreement at Exelon Corporate with a maximum program size of $600 million at both December 31, 2020 and 2019, respectively. Exelon Corporate had 0 outstanding commercial paper as of December 31, 2020 and $136 million at 2019 with an average interest rate on commercial paper borrowings of 1.92%.
(e)Represents the consolidated amounts of Pepco, DPL, and ACE.
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. A registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
At December 31, 2020, the Registrants had the following aggregate bank commitments, credit facility borrowings, and available capacity under their respective credit facilities:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Available Capacity at December 31, 2020 |
Borrower(a) | Facility Type | | Aggregate Bank
Commitment(b) | | Facility Draws | | Outstanding
Letters of Credit | | Actual | | To Support Additional Commercial
Paper(c) |
Exelon(c) | Syndicated Revolver / Bilaterals / Project Finance | | $ | 10,644 | | | $ | 0 | | | $ | 1,230 | | | $ | 9,414 | | | $ | 7,698 | |
| Generation | Syndicated Revolver | | 5,300 | | | 0 | | | 262 | | | 5,038 | | | 4,698 | |
| Generation | Bilaterals | | 1,500 | | | 0 | | | 840 | | | 660 | | | 0 | |
| Generation | Project Finance | | 144 | | | 0 | | | 119 | | | 25 | | | 0 | |
| ComEd | Syndicated Revolver | | 1,000 | | | 0 | | | 2 | | | 998 | | | 675 | |
| PECO | Syndicated Revolver | | 600 | | | 0 | | | 0 | | | 600 | | | 600 | |
| BGE | Syndicated Revolver | | 600 | | | 0 | | | 0 | | | 600 | | | 600 | |
| PHI | Syndicated Revolver | | 900 | | | 0 | | | 1 | | | 899 | | | 531 | |
| Pepco | Syndicated Revolver | | 300 | | | 0 | | | 1 | | | 299 | | | 264 | |
| DPL | Syndicated Revolver | | 300 | | | 0 | | | 0 | | | 300 | | | 154 | |
| ACE | Syndicated Revolver | | 300 | | | 0 | | | 0 | | | 300 | | | 113 | |
__________
(a)On May 26, 2018, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2023.
(b)Excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $38 million, $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. These facilities expire on October 8, 2021. These facilities are solely utilized to issue letters of credit. As of December 31, 2020, letters of credit issued under these facilities totaled $5 million, $5 million, and $2 million for Generation, ComEd, and BGE, respectively.
(c)Includes $600 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $6 million outstanding letters of credit at December 31, 2020. Exelon Corporate had $594 million in available capacity to support additional commercial paper at December 31, 2020.
On March 19, 2020, Generation borrowed $1.5 billion on its revolving credit facility due to disruptions in the commercial paper markets as a result of COVID-19. The funds were used to refinance commercial paper. Generation repaid the $1.5 billion borrowed on the revolving credit facility on April 3, 2020.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a 12-month term loan agreement for $500 million, which was renewed annually on March 22, 2018, March 20, 2019, and March 19, 2020, respectively. The loan agreement will expire on March 18, 2021. Pursuant to the loan agreement, as of December 31, 2020, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loans beared interest at LIBOR plus 0.95% as of December 31, 2019 as part of the March 20, 2019 renewal. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.
On March 19, 2020, Generation entered into a term loan agreement for $200 million. The loan agreement has an expiration of March 18, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.50% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.
On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement has an expiration of March 30, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.75% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
On January 25, 2021, ComEd entered into two 90-day term loan agreements of $125 million each with variable interest rates of LIBOR plus 0.50% and LIBOR plus 0.75%, respectively.
Revolving Credit Agreements
On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility at a variable interest rate of LIBOR plus 1.75%. This facility will be used by Exelon as an additional source of short-term liquidity as needed.
Bilateral Credit Agreements
The following table reflects the bilateral credit agreements at December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant | | Date Initiated | | Latest Amendment Date | | Maturity Date(a) | | Amount |
Generation(b) | | October 26, 2012 | | October 23, 2020 | | October 22, 2021 | | $ | 200 | |
Generation(c) | | January 11, 2013 | | January 4, 2019 | | March 1, 2021 | | 100 |
Generation(c) | | January 5, 2016 | | January 4, 2019 | | April 5, 2021 | | 150 |
Generation(c) | | February 21, 2019 | | N/A | | March 31, 2021 | | 100 |
Generation(c) | | October 25, 2019 | | N/A | | N/A | | 200 |
Generation(c) | | October 25, 2019 | | N/A | | N/A | | 100 |
Generation(c) | | November 20, 2019 | | N/A | | N/A | | 300 |
Generation(c) | | November 21, 2019 | | N/A | | N/A | | 150 |
Generation(c) | | November 21, 2019 | | N/A | | November 21, 2021 | | 100 |
Generation(c) | | May 15, 2020 | | N/A | | N/A | | 100 |
__________
(a)Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement.
(b)Bilateral credit facility relates to CENG, which is incorporated within Generation, and supports the issuance of letters of credit and funding for working capital and does not back Generation's commercial paper program. During the second and third quarters of 2020, CENG drew on its bilateral credit facility. As of December 31, 2020, there was 0 outstanding balance at this facility.
(c)Bilateral credit agreements solely support the issuance of letters of credit and do not back Generation's commercial paper program.
Borrowings under Exelon’s, Generation’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon(a) | | Generation | | ComEd | | PECO | | BGE | | | | Pepco | | DPL | | ACE |
| Prime based borrowings | 0 - 27.5 | | 27.5 | | | — | | | — | | | — | | | | | 7.5 | | | — | | | 7.5 | |
| LIBOR-based borrowings | 90.0 - 127.5 | | 127.5 | | | 100.0 | | | 90.0 | | | 90.0 | | | | | 107.5 | | | 100.0 | | | 107.5 | |
__________
(a)Includes interest rate adders at Exelon Corporate of 27.5 and 127.5 for prime and LIBOR-based borrowings, respectively.
If any registrant loses its investment grade rating, the maximum adders for prime rate borrowings and LIBOR-based rate borrowings would be 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower.
Variable Rate Demand Bonds
DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, these bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of both December 31, 2020 and December 31, 2019, $79 million in variable
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year in Exelon's, PHI's, and DPL's Consolidated Balance Sheet.
Long-Term Debt
The following tables present the outstanding long-term debt at the Registrants as of December 31, 2020 and 2019:
Exelon
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Maturity
Date | | December 31, |
| Rates | | 2020 | | 2019 |
| Long-term debt | | | | | | | | | |
| | | | | | | | | |
First mortgage bonds(a) | 0.19 | % | - | 7.90 | % | | 2021 - 2050 | | $ | 18,915 | | | $ | 17,486 | |
| Senior unsecured notes | 2.45 | % | - | 7.60 | % | | 2021 - 2050 | | 10,585 | | | 10,685 | |
| Unsecured notes | 2.40 | % | - | 6.35 | % | | 2021 - 2050 | | 3,700 | | | 3,300 | |
| Pollution control notes | 2.50 | % | - | 2.70 | % | | 2020 | | 0 | | | 412 | |
| Nuclear fuel procurement contracts | | | 3.15 | % | | 2020 | | 0 | | | 3 | |
| | | | | | | | | |
| Notes payable and other | 2.10 | % | - | 7.99 | % | | 2021 - 2053 | | 170 | | | 154 | |
| Junior subordinated notes | | | 3.50 | % | | 2022 | | 1,150 | | | 1,150 | |
| | | | | | | | | |
| Long-term software licensing agreement | | | 3.95 | % | | 2024 | | 30 | | | 55 | |
| Unsecured tax-exempt bonds | 0.17 | % | - | 1.70 | % | | 2022 - 2024 | | 143 | | | 222 | |
| Medium-terms notes (unsecured) | 0 | | 7.72 | % | | 2027 | | 10 | | | 10 | |
| Transition bonds | | | 5.55 | % | | 2021 | | 21 | | | 40 | |
| Loan agreement | | | 2.00 | % | | 2023 | | 50 | | | 50 | |
| Nonrecourse debt: | | | | | | | | | |
| Fixed rates | 2.29 | % | - | 6.00 | % | | 2031 - 2037 | | 977 | | | 1,182 | |
| Variable rates | 2.99 | % | - | 3.18 | % | | 2021 - 2027 | | 765 | | | 811 | |
| Total long-term debt | | | | | | | 36,516 | | | 35,560 | |
| Unamortized debt discount and premium, net | | | | | | | (77) | | | (72) | |
| Unamortized debt issuance costs | | | | | | | (248) | | | (214) | |
| Fair value adjustment | | | | | | | 721 | | | 765 | |
| | | | | | | | | |
| Long-term debt due within one year | | | | | | | (1,819) | | | (4,710) | |
| Long-term debt | | | | | | | $ | 35,093 | | | $ | 31,329 | |
Long-term debt to financing trusts(b) | | | | | | | | | |
| Subordinated debentures to ComEd Financing III | | | 6.35 | % | | 2033 | | $ | 206 | | | $ | 206 | |
| Subordinated debentures to PECO Trust III | 5.25 | % | - | 7.38 | % | | 2028 | | 81 | | | 81 | |
| Subordinated debentures to PECO Trust IV | | | 5.75 | % | | 2033 | | 103 | | | 103 | |
| | | | | | | | | |
| Total long-term debt to financing trusts | | | | | | | $ | 390 | | | $ | 390 | |
| | | | | | | | | |
| | | | | | | | | |
__________
(a)Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures.
(b)Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
Generation
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Maturity
Date | | December 31, |
| Rates | | 2020 | | 2019 |
| Long-term debt | | | | | | | | | |
| Senior unsecured notes | 3.25 | % | - | 7.60 | % | | 2022 - 2042 | | $ | 4,219 | | | $ | 5,420 | |
| Pollution control notes | 2.50 | % | - | 2.70 | % | | 2020 | | 0 | | | 412 | |
| Nuclear fuel procurement contracts | | | 3.15 | % | | 2020 | | 0 | | | 3 | |
| | | | | | | | | |
| Notes payable and other | 2.10 | % | - | 4.85 | % | | 2021 - 2028 | | 111 | | | 115 | |
| Nonrecourse debt: | | | | | | | | | |
| Fixed rates | 2.29 | % | - | 6.00 | % | | 2031 - 2037 | | 977 | | | 1,182 | |
| Variable rates | 2.99 | % | - | 3.18 | % | | 2021 - 2027 | | 765 | | | 811 | |
| Total long-term debt | | | | | | | 6,072 | | | 7,943 | |
| Unamortized debt discount and premium, net | | | | | | | (5) | | | (5) | |
| Unamortized debt issuance costs | | | | | | | (46) | | | (42) | |
| Fair value adjustment | | | | | | | 66 | | | 78 | |
| Long-term debt due within one year | | | | | | | (197) | | | (3,182) | |
| Long-term debt | | | | | | | $ | 5,890 | | | $ | 4,792 | |
ComEd
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Maturity
Date | | December 31, |
| Rates | | 2020 | | 2019 |
| Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 2.20 | % | - | 6.45 | % | | 2021 - 2050 | | $ | 9,079 | | | $ | 8,578 | |
| Other | | | 7.49 | % | | 2053 | | 8 | | | 8 | |
| Total long-term debt | | | | | | | 9,087 | | | 8,586 | |
| Unamortized debt discount and premium, net | | | | | | | (28) | | | (27) | |
| Unamortized debt issuance costs | | | | | | | (76) | | | (68) | |
| Long-term debt due within one year | | | | | | | (350) | | | (500) | |
| Long-term debt | | | | | | | $ | 8,633 | | | $ | 7,991 | |
Long-term debt to financing trust(b) | | | | | | | | | |
| Subordinated debentures to ComEd Financing III | | | 6.35 | % | | 2033 | | $ | 206 | | | $ | 206 | |
| Total long-term debt to financing trusts | | | | | | | 206 | | | 206 | |
| Unamortized debt issuance costs | | | | | | | (1) | | | (1) | |
| Long-term debt to financing trusts | | | | | | | $ | 205 | | | $ | 205 | |
__________
(a)Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture.
(b)Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
PECO
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Maturity
Date | | December 31, |
| Rates | | 2020 | | 2019 |
| Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 1.70 | % | - | 5.95 | % | | 2021 - 2050 | | $ | 3,750 | | | $ | 3,400 | |
| Loan agreement | | | 2.00 | % | | 2023 | | 50 | | | 50 | |
| Total long-term debt | | | | | | | 3,800 | | | 3,450 | |
| Unamortized debt discount and premium, net | | | | | | | (20) | | | (21) | |
| Unamortized debt issuance costs | | | | | | | (27) | | | (24) | |
| Long-term debt due within one year | | | | | | | (300) | | | 0 | |
| Long-term debt | | | | | | | $ | 3,453 | | | $ | 3,405 | |
Long-term debt to financing trusts(b) | | | | | | | | | |
| Subordinated debentures to PECO Trust III | 5.25 | % | - | 7.38 | % | | 2028 | | $ | 81 | | | $ | 81 | |
| Subordinated debentures to PECO Trust IV | | | 5.75 | % | | 2033 | | 103 | | | 103 | |
| | | | | | | | | |
| | | | | | | | | |
| Long-term debt to financing trusts | | | | | | | $ | 184 | | | $ | 184 | |
__________
(a)Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.
(b)Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
BGE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Maturity
Date | | December 31, |
| Rates | | 2020 | | 2019 |
| Long-term debt | | | | | | | | | |
| | | | | | | | | |
| Unsecured notes | 2.40 | % | - | 6.35 | % | | 2021 - 2050 | | $ | 3,700 | | | $ | 3,300 | |
| Total long-term debt | | | | | | | 3,700 | | | 3,300 | |
| Unamortized debt discount and premium, net | | | | | | | (12) | | | (9) | |
| Unamortized debt issuance costs | | | | | | | (24) | | | (21) | |
| Long-term debt due within one year | | | | | | | (300) | | | 0 | |
| Long-term debt | | | | | | | $ | 3,364 | | | $ | 3,270 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
PHI
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Maturity
Date | | December 31, |
| Rates | | 2020 | | 2019 |
| Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 0.19 | % | - | 7.90 | % | | 2021 - 2050 | | $ | 6,086 | | | $ | 5,508 | |
| Senior unsecured notes | | | 7.45 | % | | 2032 | | 185 | | | 185 | |
| Unsecured tax-exempt bonds | 0.17 | % | - | 1.70 | % | | 2022 - 2024 | | 143 | | | 222 | |
| Medium-terms notes (unsecured) | | | 7.72 | % | | 2027 | | 10 | | | 10 | |
| Transition bonds | | | 5.55 | % | | 2021 | | 21 | | | 40 | |
| Finance leases | | | 3.54 | % | | 2022 - 2028 | | 50 | | | 28 | |
| Other | 7.28 | % | - | 7.99 | % | | 2021 - 2022 | | 1 | | | 2 | |
| Total long-term debt | | | | | | | 6,496 | | | 5,995 | |
| Unamortized debt discount and premium, net | | | | | | | 4 | | | 4 | |
| Unamortized debt issuance costs | | | | | | | (28) | | | (19) | |
| Fair value adjustment | | | | | | | 534 | | | 583 | |
| Long-term debt due within one year | | | | | | | (347) | | | (103) | |
| Long-term debt | | | | | | | $ | 6,659 | | | $ | 6,460 | |
_________
(a)Substantially all of Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures.
Pepco
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Maturity
Date | | December 31, |
| Rates | | 2020 | | 2019 |
| Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 2.53 | % | - | 7.90 | % | | 2022 - 2050 | | $ | 3,075 | | | $ | 2,775 | |
| Unsecured tax-exempt bonds | | | 1.70 | % | | 2022 | | 110 | | | 110 | |
| Finance leases | | | 3.54 | % | | 2025 - 2028 | | 17 | | | 10 | |
| Other | 7.28 | % | - | 7.99 | % | | 2021 - 2022 | | 1 | | | 2 | |
| Total long-term debt | | | | | | | 3,203 | | | 2,897 | |
| Unamortized debt discount and premium, net | | | | | | | 2 | | | 2 | |
| Unamortized debt issuance costs | | | | | | | (40) | | | (35) | |
| Long-term debt due within one year | | | | | | | (3) | | | (2) | |
| Long-term debt | | | | | | | $ | 3,162 | | | $ | 2,862 | |
__________
(a)Substantially all of Pepco's assets are subject to the lien of its mortgage indenture.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
DPL
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Maturity
Date | | December 31, |
| Rates | | 2020 | | 2019 |
| Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 0.19 | % | - | 4.27 | % | | 2023 - 2049 | | $ | 1,624 | | | $ | 1,446 | |
| Unsecured tax-exempt bonds | 0.17 | % | - | 0.20 | % | | 2024 | | 33 | | | 112 | |
| Medium-terms notes (unsecured) | | | 7.72 | % | | 2027 | | 10 | | | 10 | |
| Finance leases | | | 3.54 | % | | 2025 - 2028 | | 20 | | | 10 | |
| Total long-term debt | | | | | | | 1,687 | | | 1,578 | |
| Unamortized debt discount and premium, net | | | | | | | 1 | | | 1 | |
| Unamortized debt issuance costs | | | | | | | (11) | | | (12) | |
| Long-term debt due within one year | | | | | | | (82) | | | (80) | |
| Long-term debt | | | | | | | $ | 1,595 | | | $ | 1,487 | |
__________
(a)Substantially all of DPL's assets are subject to the lien of its mortgage indenture.
ACE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Maturity
Date | | December 31, |
| Rates | | 2020 | | 2019 |
| Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 2.25 | % | - | 6.80 | % | | 2021 - 2050 | | $ | 1,387 | | | $ | 1,287 | |
| Transition bonds | | | 5.55 | % | | 2021 | | 21 | | | 40 | |
| Finance leases | | | 3.54 | % | | 2022 - 2028 | | 13 | | | 8 | |
| Total long-term debt | | | | | | | 1,421 | | | 1,335 | |
| Unamortized debt discount and premium, net | | | | | | | (1) | | | (1) | |
| Unamortized debt issuance costs | | | | | | | (7) | | | (7) | |
| Long-term debt due within one year | | | | | | | (261) | | | (20) | |
| Long-term debt | | | | | | | $ | 1,152 | | | $ | 1,307 | |
__________
(a)Substantially all of ACE's assets are subject to the lien of its mortgage indenture.
Long-term debt maturities at the Registrants in the periods 2021 through 2025 and thereafter are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2021 | $ | 1,819 | | | $ | 197 | | | $ | 350 | | | $ | 300 | | | $ | 300 | | | $ | 347 | | | $ | 3 | | | $ | 82 | | | $ | 261 | |
| 2022 | 3,092 | | | 1,025 | | | 0 | | | 350 | | | 250 | | | 317 | | | 312 | | | 3 | | | 2 | |
| 2023 | 859 | | | 1 | | | 0 | | | 50 | | | 300 | | | 508 | | | 3 | | | 503 | | | 2 | |
| 2024 | 814 | | | 1 | | | 250 | | | 0 | | | 0 | | | 558 | | | 403 | | | 3 | | | 152 | |
| 2025 | 2,215 | | | 900 | | | 0 | | | 350 | | | 0 | | | 158 | | | 3 | | | 3 | | | 152 | |
| Thereafter | 28,107 | | (a) | 3,948 | | | 8,692 | | (b) | 2,934 | | (c) | 2,850 | | | 4,608 | | | 2,479 | | | 1,093 | | | 852 | |
| Total | $ | 36,906 | | | $ | 6,072 | | | $ | 9,292 | | | $ | 3,984 | | | $ | 3,700 | | | $ | 6,496 | | | $ | 3,203 | | | $ | 1,687 | | | $ | 1,421 | |
__________
(a)Includes $390 million due to ComEd and PECO financing trusts.
(b)Includes $206 million due to ComEd financing trust.
(c)Includes $184 million due to PECO financing trusts.
Debt Covenants
As of December 31, 2020, the Registrants are in compliance with debt covenants.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.2 billion of generating assets have been pledged as collateral at December 31, 2020. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.
Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance will bear interest at an average blended interest rate of 2.82%. As of December 31, 2020 and December 31, 2019, approximately $460 million and $485 million were outstanding, respectively. In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2020, Generation had $37 million in letters of credit outstanding related to the project. In December 2017, Generation’s interests in Antelope Valley were contributed to and are pledged as collateral for the EGR IV financing structures referenced below.
Antelope Valley sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code, which created an event of default for Antelope Valley’s nonrecourse debt that provided the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the event of default and in the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019. Further, distributions from Antelope Valley to EGR IV were suspended.
The United States Bankruptcy Court entered an order on June 20, 2020 confirming PG&E’s plan of reorganization. On July 1, 2020 the plan became effective, and PG&E emerged from bankruptcy. On July 21, 2020, Antelope Valley received a waiver from the DOE for the event of default and, as such, distributions from Antelope Valley to EGR IV were permitted and the debt was classified as noncurrent as of June 30, 2020. The debt continues to be presented as noncurrent as of December 31, 2020.
See Note 12 — Asset Impairments for additional information.
Continental Wind, LLC. In September 2013, Continental Wind, an indirect subsidiary of Exelon and Generation, completed the issuance and sale of $613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico, and Texas with a total net capacity of 667 MW. The net proceeds were distributed to Generation for its general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2020 and December 31, 2019, approximately $415 million and $447 million were outstanding, respectively.
In addition, Continental Wind has a $122 million letter of credit facility and $4 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2020, the Continental Wind letter of credit facility had $114 million in letters of credit outstanding related to the project.
In 2017, Generation’s interests in Continental Wind were contributed to EGRP. Refer to Note 23 - Variable Interest Entities for additional information on EGRP.
Renewable Power Generation. In March 2016, RPG, an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for paydown of long term debt obligations at Sacramento PV Energy and Constellation
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
Solar Horizons and for general business purposes. The loan is scheduled to mature on March 31, 2035. The term loan bears interest at a fixed rate of 4.11% payable semi-annually. As of December 31, 2020 and December 31, 2019, approximately $95 million and $106 million were outstanding, respectively.
In 2017, Generation’s interests in RPG were contributed to EGRP. Refer to Note 23 - Variable Interest Entities for additional information on EGRP.
SolGen, LLC. In September 2016, SolGen, an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for general business purposes. The loan is scheduled to mature on September 30, 2036. The term loan bears interest at a fixed rate of 3.93% payable semi-annually. As of December 31, 2020 and December 31, 2019, approximately $125 million and $131 million were outstanding, respectively. As a result of the sale agreement with an affiliate of Brookfield Renewable in the fourth quarter of 2020, the outstanding balance was reclassified to Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets as of December 31, 2020. In 2017, Generation’s interests in SolGen were contributed to and were pledged as collateral for the EGR IV financing structure. In December 2020, as part of the EGR IV financing, SolGen was removed from the collateral terms structured within the agreement. See EGR IV discussed below for additional information and Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the sale agreement.
ExGen Renewables IV. In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement with a maturity date of November 28, 2024. In addition to the financing, EGR IV entered into interest rate swaps with an initial notional amount of $636 million at an interest rate of 2.32% to manage a portion of the interest rate exposure in connection with the financing.
In December 2020, EGR IV entered into a financing agreement for a $750 million nonrecourse senior secured term loan credit facility, scheduled to mature on December 15, 2027. The term loan bears interest at a variable rate equal to LIBOR plus 2.75%, subject to a 1% LIBOR floor with interest payable quarterly. In addition to the financing, EGR IV entered into interest rate swaps with an initial notional amount of $516 million at an interest rate of 1.05% to manage a portion of the interest rate exposure in connection with the financing.
The proceeds were used to repay the November 2017 nonrecourse senior secured term loan credit facility of $850 million, of which $709 million was outstanding as of the retirement date in December of 2020, and to settle the November 2017 interest rate swap. Generation’s interests in EGRP and Antelope Valley remained contributed to and are pledged as collateral for this financing. As of December 31, 2020, $750 million was outstanding. See Note 23 — Variable Interest Entities for additional information on EGRP and Note 16 — Derivative Financial Instruments for additional information on interest rate swaps.
18. Fair Value of Financial Assets and Liabilities (All Registrants)
Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
•Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
•Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
Fair Value of Financial Liabilities Recorded at Amortized Cost
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 2020 and 2019. The Registrants have no financial liabilities classified as Level 1.
The carrying amounts of the Registrants’ short-term liabilities as presented on their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2020 | | December 31, 2019 |
| | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| | | Level 2 | | Level 3 | | Total | | | Level 2 | | Level 3 | | Total |
Long-Term Debt, including amounts due within one year(a) |
| Exelon | | $ | 36,912 | | | $ | 40,688 | | | $ | 3,064 | | | $ | 43,752 | | | $ | 36,039 | | | $ | 37,453 | | | $ | 2,580 | | | $ | 40,033 | |
| Generation | | 6,087 | | | 5,648 | | | 1,208 | | | 6,856 | | | 7,974 | | | 7,304 | | | 1,366 | | | 8,670 | |
| ComEd | | 8,983 | | | 11,117 | | | 0 | | | 11,117 | | | 8,491 | | | 9,848 | | | 0 | | | 9,848 | |
| PECO | | 3,753 | | | 4,553 | | | 50 | | | 4,603 | | | 3,405 | | | 3,868 | | | 50 | | | 3,918 | |
| BGE | | 3,664 | | | 4,366 | | | 0 | | | 4,366 | | | 3,270 | | | 3,649 | | | 0 | | | 3,649 | |
| PHI | | 7,006 | | | 6,099 | | | 1,806 | | | 7,905 | | | 6,563 | | | 5,902 | | | 1,164 | | | 7,066 | |
| Pepco | | 3,165 | | | 3,336 | | | 748 | | | 4,084 | | | 2,864 | | | 3,198 | | | 388 | | | 3,586 | |
| DPL | | 1,677 | | | 1,484 | | | 455 | | | 1,939 | | | 1,567 | | | 1,408 | | | 311 | | | 1,719 | |
| ACE | | 1,413 | | | 1,018 | | | 602 | | | 1,620 | | | 1,327 | | | 1,026 | | | 464 | | | 1,490 | |
Long-Term Debt to Financing Trusts(a) |
| Exelon | | $ | 390 | | | $ | 0 | | | $ | 467 | | | $ | 467 | | | $ | 390 | | | $ | 0 | | | $ | 428 | | | $ | 428 | |
| ComEd | | 205 | | | 0 | | | 246 | | | 246 | | | 205 | | | 0 | | | 227 | | | 227 | |
| PECO | | 184 | | | 0 | | | 221 | | | 221 | | | 184 | | | 0 | | | 201 | | | 201 | |
| SNF Obligation |
| Exelon | | $ | 1,208 | | | $ | 909 | | | $ | 0 | | | $ | 909 | | | $ | 1,199 | | | $ | 1,055 | | | $ | 0 | | | $ | 1,055 | |
| Generation | | 1,208 | | | 909 | | | 0 | | | 909 | | | 1,199 | | | 1,055 | | | 0 | | | 1,055 | |
__________
(a) Includes unamortized debt issuance costs which are not fair valued. Refer to Note 17 — Debt and Credit Agreements for each Registrants’ unamortized debt issuance costs.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
Exelon uses the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost:
| | | | | | | | | | | |
| Type | Level | Registrants | Valuation |
| Long-Term Debt, including amounts due within one year |
| Taxable Debt Securities | 2 | All | The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. Exelon obtains credit spreads based on trades of existing Exelon debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. |
| Variable Rate Financing Debt | 2 | Exelon, Generation, DPL | Debt rates are reset on a regular basis and the carrying value approximates fair value. |
| Taxable Private Placement Debt Securities | 3 | Exelon, Pepco, DPL, ACE | Rates are obtained similar to the process for taxable debt securities. Due to low trading volume and qualitative factors such as market conditions, low volume of investors, and investor demand, these debt securities are Level 3. |
| Government Backed Fixed Rate Project Financing Debt | 3 | Exelon, Generation | The fair value is similar to the process for taxable debt securities. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable U.S. Treasury rate as well as a current market curve derived from government-backed securities. |
| Non-Government Backed Fixed Rate Nonrecourse Debt | 3 | Exelon, Generation, Pepco | Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project. |
| Long-Term Debt to Financing Trusts |
| Long Term Debt to Financing Trusts | 3 | Exelon, ComEd, PECO | Fair value is based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities and qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3. |
| SNF Obligation |
| SNF Obligation | 2 | Exelon, Generation | The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week U.S. Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2035 and 2030 for the years ended December 31, 2020 and 2019, respectively. |
Recurring Fair Value Measurements
The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy atas of December 31, 20182020 and 2017:2019:
Exelon
|
| | | | | | | | | | | | | | | | | | | |
December 31, 2018(a) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Pension plan assets | | | | | | | | | |
| Cash equivalents | $ | 350 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 350 |
|
Equities(c) | 3,364 |
| | — |
| | 2 |
| | 1,980 |
| | 5,346 |
|
| Fixed income: |
|
|
|
|
| | | |
|
| U.S. Treasury and agencies | 996 |
| | 173 |
| | — |
| | — |
| | 1,169 |
|
| State and municipal debt | — |
| | 59 |
| | — |
| | — |
| | 59 |
|
| Corporate debt | — |
| | 3,716 |
| | 216 |
| | — |
| | 3,932 |
|
Other(c) | — |
| | 329 |
| | — |
| | 613 |
| | 942 |
|
| Fixed income subtotal | 996 |
|
| 4,277 |
|
| 216 |
| | 613 |
| | 6,102 |
|
| Private equity | — |
| | — |
| | — |
| | 1,219 |
| | 1,219 |
|
| Hedge funds | — |
| | — |
| | — |
| | 1,608 |
| | 1,608 |
|
| Real estate | — |
| | — |
| | — |
| | 1,029 |
| | 1,029 |
|
| Private credit | — |
| | — |
| | 268 |
| | 798 |
| | 1,066 |
|
| Pension plan assets subtotal | $ | 4,710 |
|
| $ | 4,277 |
|
| $ | 486 |
| | $ | 7,247 |
| | $ | 16,720 |
|
|
| | | | | | | | | | | | | | | | | | | |
December 31, 2018(a) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Other postretirement benefit plan assets | | | | | | | | | |
| Cash equivalents | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
| Equities | 537 |
| | 2 |
| | — |
| | 508 |
| | 1,047 |
|
| Fixed income: |
|
|
|
|
| | | |
|
| U.S. Treasury and agencies | 11 |
| | 56 |
| | — |
| | — |
| | 67 |
|
| State and municipal debt | — |
| | 126 |
| | — |
| | — |
| | 126 |
|
| Corporate debt | — |
| | 48 |
| | — |
| | — |
| | 48 |
|
| Other | 183 |
| | 72 |
| | — |
| | 170 |
| | 425 |
|
| Fixed income subtotal | 194 |
|
| 302 |
|
| — |
|
| 170 |
| | 666 |
|
| Hedge funds | — |
| | — |
| | — |
| | 411 |
| | 411 |
|
| Real estate | — |
| | — |
| | — |
| | 132 |
| | 132 |
|
| Private credit | — |
| | — |
| | — |
| | 132 |
| | 132 |
|
| Other postretirement benefit plan assets subtotal | $ | 753 |
|
| $ | 304 |
|
| $ | — |
| | $ | 1,353 |
|
| $ | 2,410 |
|
Total pension and other postretirement benefit plan assets(e) | $ | 5,463 |
| | $ | 4,581 |
| | $ | 486 |
| | $ | 8,600 |
| | $ | 19,130 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
Exelon and Generation
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation |
| As of December 31, 2020 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Assets | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 686 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 686 | | | $ | 124 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 124 | |
| NDT fund investments | | | | | | | | | | | | | | | | | | | |
Cash equivalents(b) | 210 | | | 95 | | | 0 | | | 0 | | | 305 | | | 210 | | | 95 | | | 0 | | | 0 | | | 305 | |
| Equities | 3,886 | | | 2,077 | | | 0 | | | 1,562 | | | 7,525 | | | 3,886 | | | 2,077 | | | 0 | | | 1,562 | | | 7,525 | |
| Fixed income | | | | | | | | | | | | | | | | | | | |
Corporate debt(c) | 0 | | | 1,485 | | | 285 | | | 0 | | | 1,770 | | | 0 | | | 1,485 | | | 285 | | | 0 | | | 1,770 | |
| U.S. Treasury and agencies | 1,871 | | | 126 | | | 0 | | | 0 | | | 1,997 | | | 1,871 | | | 126 | | | 0 | | | 0 | | | 1,997 | |
| Foreign governments | 0 | | | 56 | | | 0 | | | 0 | | | 56 | | | 0 | | | 56 | | | 0 | | | 0 | | | 56 | |
| State and municipal debt | 0 | | | 101 | | | 0 | | | 0 | | | 101 | | | 0 | | | 101 | | | 0 | | | 0 | | | 101 | |
| Other | 0 | | | 41 | | | 0 | | | 961 | | | 1,002 | | | 0 | | | 41 | | | 0 | | | 961 | | | 1,002 | |
| Fixed income subtotal | 1,871 | | | 1,809 | | | 285 | | | 961 | | | 4,926 | | | 1,871 | | | 1,809 | | | 285 | | | 961 | | | 4,926 | |
| Private credit | 0 | | | 0 | | | 212 | | | 629 | | | 841 | | | 0 | | | 0 | | | 212 | | | 629 | | | 841 | |
| Private equity | 0 | | | 0 | | | 0 | | | 504 | | | 504 | | | 0 | | | 0 | | | 0 | | | 504 | | | 504 | |
| Real estate | 0 | | | 0 | | | 0 | | | 679 | | | 679 | | | 0 | | | 0 | | | 0 | | | 679 | | | 679 | |
| | | | | | | | | | | | | | | | | | | |
NDT fund investments subtotal(d)(e) | 5,967 | | | 3,981 | | | 497 | | | 4,335 | | | 14,780 | | | 5,967 | | | 3,981 | | | 497 | | | 4,335 | | | 14,780 | |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 60 | | | 0 | | | 0 | | | 0 | | | 60 | | | 4 | | | 0 | | | 0 | | | 0 | | | 4 | |
| Mutual funds | 91 | | | 0 | | | 0 | | | 0 | | | 91 | | | 29 | | | 0 | | | 0 | | | 0 | | | 29 | |
| Fixed income | 0 | | | 11 | | | 0 | | | 0 | | | 11 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Life insurance contracts | 0 | | | 87 | | | 34 | | | 0 | | | 121 | | | 0 | | | 28 | | | 0 | | | 0 | | | 28 | |
| Rabbi trust investments subtotal | 151 | | | 98 | | | 34 | | | 0 | | | 283 | | | 33 | | | 28 | | | 0 | | | 0 | | | 61 | |
Investments in equities(f) | 195 | | | 0 | | | 0 | | | 0 | | | 195 | | | 195 | | | 0 | | | 0 | | | 0 | | | 195 | |
| Commodity derivative assets | | | | | | | | | | | | | | | | | | | |
| Economic hedges | 745 | | | 1,914 | | | 1,599 | | | 0 | | | 4,258 | | | 745 | | | 1,914 | | | 1,599 | | | 0 | | | 4,258 | |
| Proprietary trading | 0 | | | 17 | | | 27 | | | 0 | | | 44 | | | 0 | | | 17 | | | 27 | | | 0 | | | 44 | |
Effect of netting and allocation of collateral(g)(h) | (607) | | | (1,597) | | | (905) | | | 0 | | | (3,109) | | | (607) | | | (1,597) | | | (905) | | | 0 | | | (3,109) | |
| Commodity derivative assets subtotal | 138 | | | 334 | | | 721 | | | 0 | | | 1,193 | | | 138 | | | 334 | | | 721 | | | 0 | | | 1,193 | |
| DPP consideration | 0 | | | 639 | | | 0 | | | 0 | | | 639 | | | 0 | | | 639 | | | 0 | | | 0 | | | 639 | |
| Total assets | 7,137 | | | 5,052 | | | 1,252 | | | 4,335 | | | 17,776 | | | 6,457 | | | 4,982 | | | 1,218 | | | 4,335 | | | 16,992 | |
| Liabilities | | | | | | | | | | | | | | | | | | | |
| Commodity derivative liabilities | | | | | | | | | | | | | | | | | | | |
| Economic hedges | (682) | | | (1,928) | | | (1,655) | | | 0 | | | (4,265) | | | (682) | | | (1,928) | | | (1,354) | | | 0 | | | (3,964) | |
| Proprietary trading | 0 | | | (21) | | | (4) | | | 0 | | | (25) | | | 0 | | | (21) | | | (4) | | | 0 | | | (25) | |
Effect of netting and allocation of collateral(g)(h) | 540 | | | 1,918 | | | 1,067 | | | 0 | | | 3,525 | | | 540 | | | 1,918 | | | 1,067 | | | 0 | | | 3,525 | |
| Commodity derivative liabilities subtotal | (142) | | | (31) | | | (592) | | | 0 | | | (765) | | | (142) | | | (31) | | | (291) | | | 0 | | | (464) | |
| Deferred compensation obligation | 0 | | | (145) | | | 0 | | | 0 | | | (145) | | | 0 | | | (42) | | | 0 | | | 0 | | | (42) | |
| Total liabilities | (142) | | | (176) | | | (592) | | | 0 | | | (910) | | | (142) | | | (73) | | | (291) | | | 0 | | | (506) | |
| Total net assets | $ | 6,995 | | | $ | 4,876 | | | $ | 660 | | | $ | 4,335 | | | $ | 16,866 | | | $ | 6,315 | | | $ | 4,909 | | | $ | 927 | | | $ | 4,335 | | | $ | 16,486 | |
|
| | | | | | | | | | | | | | | | | | | |
December 31, 2017(a)(b) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Pension plan assets | | | | | | | | | |
| Cash equivalents | $ | 585 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 585 |
|
Equities(c) | 3,565 |
| | — |
| | 2 |
| | 3,077 |
| | 6,644 |
|
| Fixed income: |
|
| |
|
| |
|
| | | |
|
|
| U.S. Treasury and agencies | 1,150 |
| | 159 |
| | — |
| | — |
| | 1,309 |
|
| State and municipal debt | — |
| | 64 |
| | — |
| | — |
| | 64 |
|
| Corporate debt | — |
| | 3,931 |
| | 232 |
| | — |
| | 4,163 |
|
Other(c) | — |
| | 447 |
| | — |
| | 756 |
| | 1,203 |
|
| Fixed income subtotal | 1,150 |
|
| 4,601 |
|
| 232 |
| | 756 |
| | 6,739 |
|
| Private equity | — |
| | — |
| | — |
| | 1,034 |
| | 1,034 |
|
| Hedge funds | — |
| | — |
| | — |
| | 1,770 |
| | 1,770 |
|
| Real estate | — |
| | — |
| | — |
| | 884 |
| | 884 |
|
Private credit(d) | — |
| | — |
| | 224 |
| | 695 |
| | 919 |
|
| Pension plan assets subtotal | $ | 5,300 |
|
| $ | 4,601 |
|
| $ | 458 |
| | $ | 8,216 |
|
| $ | 18,575 |
|
326
|
| | | | | | | | | | | | | | | | | | | |
December 31, 2017(a)(b) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Other postretirement benefit plan assets | | | | | | | | | |
| Cash equivalents | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 29 |
|
| Equities | 523 |
| | 2 |
| | — |
| | 764 |
| | 1,289 |
|
| Fixed income: |
|
|
|
|
| | | |
|
| U.S. Treasury and agencies | 13 |
| | 56 |
| | — |
| | — |
| | 69 |
|
| State and municipal debt | — |
| | 136 |
| | — |
| | — |
| | 136 |
|
| Corporate debt | — |
| | 47 |
| | — |
| | — |
| | 47 |
|
| Other | 225 |
| | 71 |
| | — |
| | 185 |
| | 481 |
|
| Fixed income subtotal | 238 |
|
| 310 |
|
| — |
| | 185 |
| | 733 |
|
| Hedge funds | — |
| | — |
| | — |
| | 430 |
| | 430 |
|
| Real estate | — |
| | — |
| | — |
| | 124 |
| | 124 |
|
| Private credit | — |
| | — |
| | — |
| | 123 |
| | 123 |
|
| Other postretirement benefit plan assets subtotal | $ | 790 |
|
| $ | 312 |
|
| $ | — |
| | $ | 1,626 |
| | $ | 2,728 |
|
Total pension and other postretirement benefit plan assets(e) | $ | 6,090 |
| | $ | 4,913 |
| | $ | 458 |
| | $ | 9,842 |
| | $ | 21,303 |
|
__________
| |
(a) | See Note 11—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy. |
| |
(b) | Effective March 31, 2017, Exelon became sponsor of FitzPatrick's defined benefit pension and other postretirement benefit plans, and assumed FitzPatrick's benefit plan obligations. |
| |
(c) | Includes derivative instruments of less than $1 million and $6 million, which have a total notional amount of $5,991 million and $3,606 million at December 31, 2018 and 2017, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss. |
| |
(d) | Prior year amounts reflect a reclassification from Not subject to leveling into Level 3. |
| |
(e) | Excludes net liabilities of $44 million and net assets of $2 million at December 31, 2018 and 2017, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation |
| As of December 31, 2019 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Assets | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 639 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 639 | | | $ | 214 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 214 | |
| NDT fund investments | | | | | | | | | | | | | | | | | | | |
Cash equivalents(b) | 365 | | | 87 | | | 0 | | | 0 | | | 452 | | | 365 | | | 87 | | | 0 | | | 0 | | | 452 | |
| Equities | 3,353 | | | 1,801 | | | 0 | | | 1,388 | | | 6,542 | | | 3,353 | | | 1,801 | | | 0 | | | 1,388 | | | 6,542 | |
| Fixed income | | | | | | | | | | | | | | | | | | | |
Corporate debt(c) | 0 | | | 1,421 | | | 257 | | | 0 | | | 1,678 | | | 0 | | | 1,421 | | | 257 | | | 0 | | | 1,678 | |
| U.S. Treasury and agencies | 1,808 | | | 131 | | | 0 | | | 0 | | | 1,939 | | | 1,808 | | | 131 | | | 0 | | | 0 | | | 1,939 | |
| Foreign governments | 0 | | | 42 | | | 0 | | | 0 | | | 42 | | | 0 | | | 42 | | | 0 | | | 0 | | | 42 | |
| State and municipal debt | 0 | | | 90 | | | 0 | | | 0 | | | 90 | | | 0 | | | 90 | | | 0 | | | 0 | | | 90 | |
| Other | 0 | | | 33 | | | 0 | | | 953 | | | 986 | | | 0 | | | 33 | | | 0 | | | 953 | | | 986 | |
| Fixed income subtotal | 1,808 | | | 1,717 | | | 257 | | | 953 | | | 4,735 | | | 1,808 | | | 1,717 | | | 257 | | | 953 | | | 4,735 | |
| Private credit | 0 | | | 0 | | | 254 | | | 508 | | | 762 | | | 0 | | | 0 | | | 254 | | | 508 | | | 762 | |
| Private equity | 0 | | | 0 | | | 0 | | | 402 | | | 402 | | | 0 | | | 0 | | | 0 | | | 402 | | | 402 | |
| Real estate | 0 | | | 0 | | | 0 | | | 607 | | | 607 | | | 0 | | | 0 | | | 0 | | | 607 | | | 607 | |
| | | | | | | | | | | | | | | | | | | |
NDT fund investments subtotal(d)(e) | 5,526 | | | 3,605 | | | 511 | | | 3,858 | | | 13,500 | | | 5,526 | | | 3,605 | | | 511 | | | 3,858 | | | 13,500 | |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 50 | | | 0 | | | 0 | | | 0 | | | 50 | | | 4 | | | 0 | | | 0 | | | 0 | | | 4 | |
| Mutual funds | 81 | | | 0 | | | 0 | | | 0 | | | 81 | | | 25 | | | 0 | | | 0 | | | 0 | | | 25 | |
| Fixed income | 0 | | | 12 | | | 0 | | | 0 | | | 12 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Life insurance contracts | 0 | | | 78 | | | 41 | | | 0 | | | 119 | | | 0 | | | 25 | | | 0 | | | 0 | | | 25 | |
| Rabbi trust investments subtotal | 131 | | | 90 | | | 41 | | | 0 | | | 262 | | | 29 | | | 25 | | | 0 | | | 0 | | | 54 | |
| Commodity derivative assets | | | | | | | | | | | | | | | | | | | |
| Economic hedges | 768 | | | 2,491 | | | 1,485 | | | 0 | | | 4,744 | | | 768 | | | 2,491 | | | 1,485 | | | 0 | | | 4,744 | |
| Proprietary trading | 0 | | | 37 | | | 60 | | | 0 | | | 97 | | | 0 | | | 37 | | | 60 | | | 0 | | | 97 | |
Effect of netting and allocation of collateral(g)(h) | (908) | | | (2,162) | | | (588) | | | 0 | | | (3,658) | | | (908) | | | (2,162) | | | (588) | | | 0 | | | (3,658) | |
| Commodity derivative assets subtotal | (140) | | | 366 | | | 957 | | | 0 | | | 1,183 | | | (140) | | | 366 | | | 957 | | | 0 | | | 1,183 | |
| Total assets | 6,156 | | | 4,061 | | | 1,509 | | | 3,858 | | | 15,584 | | | 5,629 | | | 3,996 | | | 1,468 | | | 3,858 | | | 14,951 | |
| Liabilities | | | | | | | | | | | | | | | | | | | |
| Commodity derivative liabilities | | | | | | | | | | | | | | | | | | | |
| Economic hedges | (1,071) | | | (2,855) | | | (1,228) | | | 0 | | | (5,154) | | | (1,071) | | | (2,855) | | | (927) | | | 0 | | | (4,853) | |
| Proprietary trading | 0 | | | (34) | | | (15) | | | 0 | | | (49) | | | 0 | | | (34) | | | (15) | | | 0 | | | (49) | |
Effect of netting and allocation of collateral(g)(h) | 1,071 | | | 2,714 | | | 802 | | | 0 | | | 4,587 | | | 1,071 | | | 2,714 | | | 802 | | | 0 | | | 4,587 | |
| Commodity derivative liabilities subtotal | 0 | | | (175) | | | (441) | | | 0 | | | (616) | | | 0 | | | (175) | | | (140) | | | 0 | | | (315) | |
| Deferred compensation obligation | 0 | | | (147) | | | 0 | | | 0 | | | (147) | | | 0 | | | (41) | | | 0 | | | 0 | | | (41) | |
| Total liabilities | 0 | | | (322) | | | (441) | | | 0 | | | (763) | | | 0 | | | (216) | | | (140) | | | 0 | | | (356) | |
| Total net assets | $ | 6,156 | | | $ | 3,739 | | | $ | 1,068 | | | $ | 3,858 | | | $ | 14,821 | | | $ | 5,629 | | | $ | 3,780 | | | $ | 1,328 | | | $ | 3,858 | | | $ | 14,595 | |
__________
(a)Exelon excludes cash of $409 million and $373 million at December 31, 2020 and 2019, respectively, and restricted cash of $59 million and $110 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $53 million and $177 million at December 31, 2020 and 2019, respectively, which is reported in Other deferred debits in
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
the Consolidated Balance Sheets. Generation excludes cash of $171 million and $177 million at December 31, 2020 and 2019, respectively, and restricted cash of $20 million and $58 million at December 31, 2020 and 2019, respectively.
(b)Includes $116 million and $90 million of cash received from outstanding repurchase agreements at December 31, 2020 and 2019, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (e) below.
(c)Includes investments in equities sold short of $(62) million and $(48) million as of December 31, 2020 and 2019, respectively, held in an investment vehicle primarily to hedge the equity option component of its convertible debt.
(d)Includes derivative assets of $2 million and $2 million, which have total notional amounts of $1,043 million and $724 million at December 31, 2020 and 2019, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of Exelon and Generation's exposure to credit or market loss.
(e)Excludes net liabilities of $181 million and $147 million at December 31, 2020 and 2019, respectively, which include certain derivative assets that have notional amounts of $104 million and $99 million at December 31, 2020 and 2019, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.
(f)Reflects equity investments held by Generation which were previously designated as equity investments without readily determinable fair values but are now publicly traded and therefore have readily determinable fair values. Generation recorded the fair value of these investments in Other current assets on Exelon's and Generation's Consolidated Balance Sheets based on the quoted market prices of the stocks at December 31, 2020, which resulted in an unrealized gain of $186 million within Other, net in Exelon's and Generation's Consolidated Statement of Operations and Comprehensive Income for the year ended December 31, 2020.
(g)Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $(67) million, $321 million, and $162 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2020. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $163 million, $551 million, and $214 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2019.
(h)Of the collateral posted/(received), $209 million and $511 million represents variation margin on the exchanges as of December 31, 2020 and 2019, respectively.
As of December 31, 2020, Exelon and Generation have outstanding commitments to invest in private credit, private equity, and real estate investments of approximately $195 million, $254 million, and $369 million, respectively. These commitments will be funded by Generation’s existing NDT funds.
Exelon and Generation held investments without readily determinable fair values with carrying amounts of $73 million and $55 million as of December 31, 2020, respectively. Exelon and Generation held investments without readily determinable fair values with carrying amounts of $69 million as of December 31, 2019. Changes in fair value, cumulative adjustments, and impairments were not material for the years ended December 31, 2020 and December 31, 2019.
ComEd, PECO, and BGE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ComEd | | PECO | | BGE |
| As of December 31, 2020 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 285 | | | $ | 0 | | | $ | 0 | | | $ | 285 | | | $ | 8 | | | $ | 0 | | | $ | 0 | | | $ | 8 | | | $ | 120 | | | $ | 0 | | | $ | 0 | | | $ | 120 | |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | |
| Mutual funds | 0 | | | 0 | | | 0 | | | 0 | | | 9 | | | 0 | | | 0 | | | 9 | | | 10 | | | 0 | | | 0 | | | 10 | |
| Life insurance contracts | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 13 | | | 0 | | | 13 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Rabbi trust investments subtotal | 0 | | | 0 | | | 0 | | | 0 | | | 9 | | | 13 | | | 0 | | | 22 | | | 10 | | | 0 | | | 0 | | | 10 | |
| Total assets | 285 | | | 0 | | | 0 | | | 285 | | | 17 | | | 13 | | | 0 | | | 30 | | | 130 | | | 0 | | | 0 | | | 130 | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
Mark-to-market derivative liabilities(b) | 0 | | | 0 | | | (301) | | | (301) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred compensation obligation | 0 | | | (8) | | | 0 | | | (8) | | | 0 | | | (9) | | | 0 | | | (9) | | | 0 | | | (5) | | | 0 | | | (5) | |
| Total liabilities | 0 | | | (8) | | | (301) | | | (309) | | | 0 | | | (9) | | | 0 | | | (9) | | | 0 | | | (5) | | | 0 | | | (5) | |
| Total net assets (liabilities) | $ | 285 | | | $ | (8) | | | $ | (301) | | | $ | (24) | | | $ | 17 | | | $ | 4 | | | $ | 0 | | | $ | 21 | | | $ | 130 | | | $ | (5) | | | $ | 0 | | | $ | 125 | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ComEd | | PECO | | BGE |
| As of December 31, 2019 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 280 | | | $ | 0 | | | $ | 0 | | | $ | 280 | | | $ | 15 | | | $ | 0 | | | $ | 0 | | | $ | 15 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | |
| Mutual funds | 0 | | | 0 | | | 0 | | | 0 | | | 8 | | | 0 | | | 0 | | | 8 | | | 8 | | | 0 | | | 0 | | | 8 | |
| Life insurance contracts | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 11 | | | 0 | | | 11 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Rabbi trust investments subtotal | 0 | | | 0 | | | 0 | | | 0 | | | 8 | | | 11 | | | 0 | | | 19 | | | 8 | | | 0 | | | 0 | | | 8 | |
| Total assets | 280 | | | 0 | | | 0 | | | 280 | | | 23 | | | 11 | | | 0 | | | 34 | | | 8 | | | 0 | | | 0 | | | 8 | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
Mark-to-market derivative liabilities(b) | 0 | | | 0 | | | (301) | | | (301) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Deferred compensation obligation | 0 | | | (8) | | | 0 | | | (8) | | | 0 | | | (9) | | | 0 | | | (9) | | | 0 | | | (5) | | | 0 | | | (5) | |
| Total liabilities | 0 | | | (8) | | | (301) | | | (309) | | | 0 | | | (9) | | | 0 | | | (9) | | | 0 | | | (5) | | | 0 | | | (5) | |
| Total net assets (liabilities) | $ | 280 | | | $ | (8) | | | $ | (301) | | | $ | (29) | | | $ | 23 | | | $ | 2 | | | $ | 0 | | | $ | 25 | | | $ | 8 | | | $ | (5) | | | $ | 0 | | | $ | 3 | |
__________
(a)ComEd excludes cash of $83 million and $90 million at December 31, 2020 and 2019, respectively, and restricted cash of $37 million and $33 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $43 million and $163 million at December 31, 2020 and 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $18 million and $12 million at December 31, 2020 and 2019, respectively. BGE excludes cash of $24 million at both December 31, 2020 and 2019, respectively, and restricted cash of $1 million at both December 31, 2020 and 2019, respectively.
(b)The Level 3 balance consists of the current and noncurrent liability of $33 million and $268 million, respectively, at December 31, 2020 and $32 million and $269 million, respectively, at December 31, 2019 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
PHI, Pepco, DPL, and ACE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2020 | | As of December 31, 2019 |
| PHI | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 86 | | | $ | 0 | | | $ | 0 | | | $ | 86 | | | $ | 124 | | | $ | 0 | | | $ | 0 | | | $ | 124 | |
| | | | | | | | | | | | | | | |
| Rabbi trust investments | | | | | | | | | | | | | | | |
| Cash equivalents | 55 | | | 0 | | | 0 | | | 55 | | | 44 | | | 0 | | | 0 | | | 44 | |
| Mutual funds | 14 | | | 0 | | | 0 | | | 14 | | | 14 | | | 0 | | | 0 | | | 14 | |
| Fixed income | 0 | | | 11 | | | 0 | | | 11 | | | 0 | | | 12 | | | 0 | | | 12 | |
| Life insurance contracts | 0 | | | 26 | | | 34 | | | 60 | | | 0 | | | 24 | | | 41 | | | 65 | |
| Rabbi trust investments subtotal | 69 | | | 37 | | | 34 | | | 140 | | | 58 | | | 36 | | | 41 | | | 135 | |
| Total assets | 155 | | | 37 | | | 34 | | | 226 | | | 182 | | | 36 | | | 41 | | | 259 | |
| Liabilities | | | | | | | | | | | | | | | |
| Deferred compensation obligation | 0 | | | (17) | | | 0 | | | (17) | | | 0 | | | (19) | | | 0 | | | (19) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Total liabilities | 0 | | | (17) | | | 0 | | | (17) | | | 0 | | | (19) | | | 0 | | | (19) | |
| Total net assets | $ | 155 | | | $ | 20 | | | $ | 34 | | | $ | 209 | | | $ | 182 | | | $ | 17 | | | $ | 41 | | | $ | 240 | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pepco | | DPL | | ACE |
| As of December 31, 2020 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 35 | | | $ | 0 | | | $ | 0 | | | $ | 35 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 13 | | | $ | 0 | | | $ | 0 | | | $ | 13 | |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 53 | | | 0 | | | 0 | | | 53 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Fixed income | 0 | | | 2 | | | 0 | | | 2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Life insurance contracts | 0 | | | 26 | | | 34 | | | 60 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Rabbi trust investments subtotal | 53 | | | 28 | | | 34 | | | 115 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total assets | 88 | | | 28 | | | 34 | | | 150 | | | 0 | | | 0 | | | 0 | | | 0 | | | 13 | | | 0 | | | 0 | | | 13 | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred compensation obligation | 0 | | | (2) | | | 0 | | | (2) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total liabilities | 0 | | | (2) | | | 0 | | | (2) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total net assets | $ | 88 | | | $ | 26 | | | $ | 34 | | | $ | 148 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 13 | | | $ | 0 | | | $ | 0 | | | $ | 13 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pepco | | DPL | | ACE |
| As of December 31, 2019 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 34 | | | $ | 0 | | | $ | 0 | | | $ | 34 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 16 | | | $ | 0 | | | $ | 0 | | | $ | 16 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 43 | | | 0 | | | 0 | | | 43 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Fixed income | 0 | | | 2 | | | 0 | | | 2 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Life insurance contracts | 0 | | | 24 | | | 41 | | | 65 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Rabbi trust investments subtotal | 43 | | | 26 | | | 41 | | | 110 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total assets | 77 | | | 26 | | | 41 | | | 144 | | | 0 | | | 0 | | | 0 | | | 0 | | | 16 | | | 0 | | | 0 | | | 16 | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred compensation obligation | 0 | | | (2) | | | 0 | | | (2) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total liabilities | 0 | | | (2) | | | 0 | | | (2) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total net assets | $ | 77 | | | $ | 24 | | | $ | 41 | | | $ | 142 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 16 | | | $ | 0 | | | $ | 0 | | | $ | 16 | |
__________
(a)PHI excludes cash of $74 million and $57 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $10 million and $14 million at December 31, 2020 and 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $30 million and $29 million at December 31, 2020 and 2019, respectively. DPL excludes cash of $15 million and $13 million at December 31, 2020 and 2019, respectively. ACE excludes cash of $17 million and $12 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $10 million and $14 million at December 31, 2020 and 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
Reconciliation of Level 3 Assets and Liabilities
The following table presentstables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PHI and Pepco | | |
| For the year ended December 31, 2020 | Total | | NDT Fund Investments | | Mark-to-Market
Derivatives | | Total Generation | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | Eliminated in Consolidation |
| Balance as of January 1, 2020 | $ | 1,068 | | | $ | 511 | | | $ | 817 | | | $ | 1,328 | | | $ | (301) | | | $ | 41 | | | $ | 0 | |
| | | | | | | | | | | | | |
| Total realized / unrealized gains (losses) | | | | | | | | | | | | | |
| Included in net income | (409) | | | 2 | | | (414) | | (a) | (412) | | | 0 | | | 3 | | | 0 | |
| Included in noncurrent payables to affiliates | 0 | | | 21 | | | 0 | | | 21 | | | 0 | | | 0 | | | (21) | |
| Included in regulatory assets/liabilities | 21 | | | 0 | | | 0 | | | 0 | | | 0 | | (b) | 0 | | | 21 | |
| Change in collateral | (53) | | | 0 | | | (53) | | | (53) | | | 0 | | | 0 | | | 0 | |
| Purchases, sales, issuances and settlements | | | | | | | | | | | | | |
| Purchases | 151 | | | 8 | | | 143 | | | 151 | | | 0 | | | 0 | | | 0 | |
| Sales | (27) | | | 0 | | | (27) | | | (27) | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | |
| Settlements | (55) | | | (45) | | | 0 | |
| (45) | | | 0 | | | (10) | | | 0 | |
| Transfers into Level 3 | (12) | | | 0 | | | (12) | | (c) | (12) | | | 0 | | | 0 | | | 0 | |
| Transfers out of Level 3 | (24) | | | 0 | | | (24) | | (c) | (24) | | | 0 | | | 0 | | | 0 | |
| Balance as of December 31, 2020 | $ | 660 | | | $ | 497 | | | $ | 430 | | | $ | 927 | | | $ | (301) | | | $ | 34 | | | $ | 0 | |
| The amount of total gains included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2020 | $ | 11 | | | $ | 2 | | | $ | 6 | | | $ | 8 | | | $ | 0 | | | $ | 3 | | | $ | 0 | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PHI and Pepco | | |
| For the year ended December 31, 2019 | Total | | NDT Fund Investments | | Mark-to-Market
Derivatives | | Total Generation | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | Eliminated in Consolidation |
| Balance as of January 1, 2019 | $ | 907 | | | $ | 543 | | | $ | 575 | | | $ | 1,118 | | | $ | (249) | | | $ | 38 | | | $ | 0 | |
| | | | | | | | | | | | | |
| Total realized / unrealized gains (losses) | | | | | | | | | | | | | |
| Included in net income | (23) | | | 5 | | | (31) | | (a) | (26) | | | 0 | | | 3 | | | 0 | |
| Included in noncurrent payables to affiliates | 0 | | | 34 | | | 0 | | | 34 | | | 0 | | | 0 | | | (34) | |
| Included in regulatory assets/liabilities | (18) | | | 0 | | | 0 | | | 0 | | | (52) | | (b) | 0 | | | 34 | |
| Change in collateral | 138 | | | 0 | | | 138 | | | 138 | | | 0 | | | 0 | | | 0 | |
| Purchases, sales, issuances and settlements | | | | | | | | | | | | | |
| Purchases | 176 | | | 44 | | | 132 | | | 176 | | | 0 | | | 0 | | | 0 | |
| Sales | (23) | | | (21) | | | (2) | | | (23) | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | |
| Settlements | (89) | | | (94) | | | 5 | |
| (89) | | | 0 | | | 0 | | | 0 | |
| Transfers into Level 3 | 5 | | | 0 | | | 5 | | (c) | 5 | | | 0 | | | 0 | | | 0 | |
| Transfers out of Level 3 | (5) | | | 0 | | | (5) | | (c) | (5) | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | |
| Balance as of December 31, 2019 | $ | 1,068 | | | $ | 511 | | | $ | 817 | | | $ | 1,328 | | | $ | (301) | | | $ | 41 | | | $ | 0 | |
| The amount of total gains included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2019 | $ | 359 | | | $ | 5 | | | $ | 351 | | | $ | 356 | | | $ | 0 | | | $ | 3 | | | $ | 0 | |
__________
(a)Includes a reduction for pensionthe reclassification of $420 million and other postretirement benefit plans$377 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 20182020 and 2017:2019, respectively.
Exelon
|
| | | | | | | | | | | | | | | |
| | Fixed Income | | Equities | | Private Credit | | Total |
| Pension Assets | | | | | | | |
| Balance as of January 1, 2018 | $ | 232 |
|
| $ | 2 |
| | $ | 224 |
| | $ | 458 |
|
| Actual return on plan assets: |
|
|
| | | |
|
|
Relating to assets still held at the
reporting date | (14 | ) |
| — |
| | 9 |
| | (5 | ) |
Relating to assets sold during the period | (1 | ) |
| — |
| | — |
| | (1 | ) |
| Purchases, sales and settlements: |
|
|
| | | |
|
|
| Purchases | 19 |
|
| — |
| | 35 |
| | 54 |
|
| Sales | (8 | ) |
| — |
| | — |
| | (8 | ) |
Settlements(b) | (12 | ) |
| — |
| | — |
| | (12 | ) |
| Balance as of December 31, 2018 | $ | 216 |
|
| $ | 2 |
| | $ | 268 |
| | $ | 486 |
|
|
| | | | | | | | | | | | | | | |
| | Fixed income | | Equities | | Private Credit (a) | | Total |
| Pension Assets | | | | | | | |
| Balance as of January 1, 2017 | $ | 206 |
|
| $ | 2 |
| | $ | 229 |
| | $ | 437 |
|
| Actual return on plan assets: |
|
|
| | | |
|
|
Relating to assets still held at the reporting date | 11 |
|
| — |
| | 29 |
| | 40 |
|
| Purchases, sales and settlements: |
|
|
| | | |
|
|
| Purchases | 31 |
|
| — |
| | 5 |
| | 36 |
|
| Sales | (16 | ) |
| — |
| | — |
| | (16 | ) |
Settlements(b) | — |
|
| — |
| | (39 | ) | | (39 | ) |
| Balance as of December 31, 2017 | $ | 232 |
|
| $ | 2 |
|
| $ | 224 |
| | $ | 458 |
|
__________
| |
(a) | Prior year amounts reflect a reclassification from Not subject to leveling into Level 3. |
| |
(b) | Represents cash settlements only. |
There were no significant transfers between Level 1(b)Includes $33 million of decreases in fair value and Level 2 duringan increase for realized losses due to settlements of $33 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 20182020. Includes $78 million of decreases in fair value and an increase for realized losses due to settlements of $26 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the pensionyear ended December 31, 2019.
(c)Transfers into and other postretirement benefit plan assets.out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.
The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Exelon | | Generation | | PHI and Pepco |
| Operating
Revenues | | Purchased
Power and
Fuel | | Operating and Maintenance | | Other, net | | Operating
Revenues | | Purchased
Power and
Fuel | | Other, net | | Operating and
Maintenance |
| | | | | | | | | | | | | | | |
| Total (losses) gains included in net income for the year ended December 31, 2020 | $ | (404) | | | $ | (10) | | | $ | 3 | | | $ | 2 | | | $ | (404) | | | $ | (10) | | | $ | 2 | | | $ | 3 | |
| | | | | | | | | | | | | | | |
| Change in unrealized (losses) gains relating to assets and liabilities held for the year ended December 31, 2020 | (31) | | | 37 | | | 3 | | | 2 | | | (31) | | | 37 | | | 2 | | | 3 | |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | PHI and Pepco |
| Operating
Revenues | | Purchased
Power and
Fuel | | Operating and Maintenance | | Other, net | | Operating
Revenues | | Purchased
Power and
Fuel | | Other, net | | Operating and
Maintenance |
| | | | | | | | | | | | | | | |
| Total gains (losses) included in net income for the year ended December 31, 2019 | $ | 219 | | | $ | (245) | | | $ | 3 | | | $ | 5 | | | $ | 219 | | | $ | (245) | | | $ | 5 | | | $ | 3 | |
| | | | | | | | | | | | | | | |
| Change in unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2019 | 546 | | | (195) | | | 3 | | | 5 | | | 546 | | | (195) | | | 5 | | | 3 | |
Valuation Techniques Used to Determine Fair Value
Cash equivalents.Equivalents (All Registrants).Investments with original maturities of three months or less when purchased, including certain short-term fixed income securitiesmutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.
NDT Fund Investments (Exelon and Generation). The trust fund investments have been established to satisfy Generation’s and CENG's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in equities and fixed income. Generation’s and CENG's NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments, including private credit, private equity, and real estate. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.
Equities. Equities These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Exelon isand Generation are able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. EquityThe equity securities that are held directly by the trust funds are valued based on quoted prices in active
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
markets and are categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.
Equity commingled funds and mutual funds are maintained by investment companies, and certainfund investments are held in accordance with a stated set of fund objectives, which are consistent with the plans’ overall investment strategy.objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.
Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.SU.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Exelon hasand Generation have obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon and Generation selectively corroborates
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
corroborate the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2.
Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold certainfund investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy.objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.
Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.
Private equity. Private equity investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments and investments in natural resources. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows and market based comparable data. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
Hedge funds. Hedge fund investments include those seeking to maximize absolute returns using a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate.
Real estate. Real estate funds are funds with a direct investment in pools of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
sources with professional qualifications. These valuation inputs are not highly observable. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
Private credit.Private credit investments primarily consist of limited partnerships that investinvestments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and include unobservable inputs such as cost, operating results,income models and discounted cash flows.typically cannot be redeemed until maturity of the term loan. Private credit investments held directly by Exelon and Generation are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. For managed private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Managed private credit fund investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient.
Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon's understanding of the investment funds. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market based comparable data. These valuation inputs are unobservable. The fair value of private credit funds areequity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
Defined Contribution Savings Plan (All Registrants)Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are reported by the fund manager and are generally based on independent appraisals from sources with professional qualifications, typically using a combination of market comparables and discounted cash flows. These valuation inputs are unobservable. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matching contributions to the savings planGeneration evaluated its NDT portfolios for the years endedexistence of significant concentrations of credit risk as of December 31, 2018, 20172020. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and 2016:individual fund. As of December 31, 2020, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.
See Note 10 — Asset Retirement Obligations for additional information on the NDT fund investments. See Note 15 — Retirement Benefits for the valuation techniques used for hedge fund investments.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, | Exelon(a) | | Generation(a) | | ComEd | | PECO | | BGE | | BSC(b) | | Pepco(c) | | DPL(c) | | ACE | | PHISCO(c)(d) |
| 2018 | $ | 179 |
| | $ | 86 |
|
| $ | 37 |
|
| $ | 9 |
|
| $ | 12 |
|
| $ | 22 |
| | $ | 3 |
| | $ | 2 |
| | $ | 2 |
| | $ | 6 |
|
| 2017 | 128 |
| | 55 |
|
| 31 |
|
| 10 |
|
| 10 |
|
| 9 |
| | 3 |
| | 2 |
| | 2 |
| | 6 |
|
| 2016 | 164 |
| | 79 |
|
| 34 |
|
| 10 |
|
| 12 |
|
| 19 |
| | 3 |
| | 2 |
| | 2 |
| | 6 |
|
|
| | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| PHI | For the Year Ended December 31, 2018 | | For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Saving Plan Matching Contributions | $ | 13 |
| | $ | 13 |
| | $ | 10 |
| | | $ | 3 |
|
__________
| |
(a) | Includes $13 million related to CENG for the year ended December 31, 2016. |
| |
(b) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above. |
| |
(c) | Pepco's, DPL's and PHISCO's matching contributions include $1 million, $1 million and $1 million, respectively, of costs incurred prior to the closing of Exelon's merger with PHI on March 23, 2016, which is not included in Exelon's matching contributions for the year ended December 31, 2016. |
| |
(d) | These amounts primarily represent amounts billed to Pepco, DPL, and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts above. |
17. Severance (All Registrants)
The Registrants have an ongoing severance plan under which, in general, the longer an employee worked prior to termination the greater the amountTable of severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the Registrants measure the obligation and record the expense at fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Severance Liability
Amounts included in the table below represent the severance liability recorded for employeesNote 18 — Fair Value of each Registrant. Exelon's severance liability includes amounts related to BSC that are billed through intercompany allocations.
Financial Assets and Liabilities
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Severance Liability | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance at December 31, 2016 | $ | 88 |
| | $ | 36 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Severance costs(a) | 35 |
| | 31 |
| | 2 |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
| Payments | (29 | ) | | (9 | ) | | (2 | ) | | — |
| | — |
| | (12 | ) | | — |
| | — |
| | — |
|
| Balance at December 31, 2017 | $ | 94 |
| | $ | 58 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 20 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Severance costs(a) | 35 |
| | 9 |
| | 1 |
| | — |
| | 1 |
| | 5 |
| | 1 |
| | — |
| | — |
|
| Payments | (52 | ) | | (20 | ) | | (2 | ) | | — |
| | — |
| | (18 | ) | | (1 | ) | | — |
| | — |
|
| Balance at December 31, 2018 | $ | 77 |
|
| $ | 47 |
|
| $ | 2 |
|
| $ | — |
|
| $ | 1 |
|
| $ | 7 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
__________
| |
(a) | Includes salary continuance and health and welfare severance benefits. |
Severance Costs Related to the PHI Merger
Upon closing the PHI Merger, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. Cash payments under the plan began in May 2016 and will continue through 2020.
For the years ended December 31, 2018 and December 31, 2017, the PHI Merger severance costs were immaterial. For the year ended December 31, 2016, the Registrants recorded the following severance costs associated with the identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Severance Benefits | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Severance costs(a) | $ | 57 |
| | $ | 9 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 44 |
| | $ | 21 |
| | $ | 13 |
| | $ | 10 |
|
| |
(a) | The amounts above forRabbi Trust Investments (Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE include $8 million, $2 million, $1 million, $1 million, $20 million, $12 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations.
|
PHI, Pepco, DPL, and ACE recorded regulatoryACE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for merger related integration costs which include a portioncertain active and retired members of these severance costs. These regulatoryExelon’s executive management and directors. The Rabbi trusts' assets are either currently being recoveredincluded in ratesinvestments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are deemed probablecategorized in Level 2. The life insurance policies are valued using the cash surrender value of recoverythe policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3, where the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in future rates.valuing these investments is not reasonably available to Exelon. Therefore, Exelon has not disclosed such inputs.
Deferred Compensation Obligations (All Registrants). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.
The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.
Investments in Equities (Exelon and Generation).Exelon and Generation hold certain investments in equity securities with readily determinable fair values in addition to those held within the NDT funds. These equity securities are valued based on quoted prices in active markets and are categorized as Level 1.
Deferred Purchase Price Consideration (Exelon and Generation). Exelon and Generation have DPP consideration for the sale of certain receivables of retail electricity at Generation. This amount is valued based on the sales price of the receivables net of allowance for credit losses based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. Since the DPP consideration is based on the sales price of the receivables, it is categorized as Level 2 in the fair value hierarchy. See Note 46 — Regulatory MattersAccounts Receivable for additional information.information on the sale of certain receivables.
Mark-to-Market Derivatives (Exelon, Generation, and ComEd). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads, and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominantly at liquid trading points.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
18. Shareholders' Equity (Exelon,For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.
For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data, in their assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements.
Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, and credit enhancements.
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.49 and $0.38 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.
On December 17, 2010, ComEd PECO, BGE, Pepco, DPLentered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and ACE)associated RECs. See Note 16 — Derivative Financial Instruments for additional information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.
See Note 16 — Derivative Financial Instruments for additional information on mark-to-market derivatives.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
The following table presents common stock authorizedthe significant inputs to the forward curve used to value these positions:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Type of trade | | Fair Value at December 31, 2020 | | Fair Value at December 31, 2019 | | Valuation
Technique | | Unobservable
Input | | 2020 Range & Arithmetic Average | | 2019 Range & Arithmetic Average |
Mark-to-market derivatives—Economic hedges (Exelon and Generation)(a)(b) | | $ | 245 | | | $ | 558 | | | Discounted Cash Flow | | Forward power
price | | $2.25 | - | $163 | $30 | | $9 | - | $180 | $29 |
| | | | | | | | Forward gas
price | | $1.57 | - | $7.88 | $2.59 | | $0.83 | - | $10.72 | $2.55 |
| | | | | | Option
Model | | Volatility
percentage | | 11% | - | 237% | 32% | | 8% | - | 236% | 70% |
| | | | | | | | | | | | | | | | | | |
Mark-to-market derivatives—Proprietary trading (Exelon and Generation)(a)(b) | | $ | 23 | | | $ | 45 | | | Discounted Cash Flow | | Forward power
price | | $10 | - | $106 | $27 | | $25 | - | $180 | $33 |
| | | | | | | | | | | | | | | | | | |
| Mark-to-market derivatives (Exelon and ComEd) | | $ | (301) | | | $ | (301) | | | Discounted Cash Flow | | Forward heat rate(c) | | 8x | - | 9x | 8.85x | | 9x | - | 10x | 9.68x |
| | | | | | | | Marketability
reserve | | 3% | - | 8% | 4.93% | | 3% | - | 7% | 4.95% |
| | | | | | | | Renewable
factor | | 91% | - | 123% | 99% | | 91% | - | 123% | 99% |
__________
(a)The valuation techniques, unobservable inputs, ranges, and outstandingarithmetic averages are the same for the asset and liability positions.
(b)The fair values do not include cash collateral posted on level three positions of $162 million and $214 million as of December 31, 2020 and December 31, 2019, respectively.
(c)Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.
The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
19. Commitments and Contingencies(All Registrants)
Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the PHI merger in Delaware, New Jersey, Maryland, and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE as of December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Description | Exelon | | PHI | | Pepco | | DPL | | ACE |
| Total commitments | $ | 513 | | | $ | 320 | | | $ | 120 | | | $ | 89 | | | $ | 111 | |
Remaining commitments(a) | 82 | | | 67 | | | 55 | | | 7 | | | 5 | |
__________
(a)Remaining commitments extend through 2026 and include rate credits, energy efficiency programs, and delivery system modernization.
In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia, and Delaware at an estimated cost of approximately $135 million, which will generate future earnings at Exelon and Generation. Investment costs, which are expected to be primarily capital in nature, are recognized as incurred and recorded in Exelon's and Generation's financial statements. As of December 31, 2020, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $119 million. Exelon has also committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and 2017:resulted in a proposed REC purchase agreement that was approved by the DPSC in March 2019. The third and final 40 MW wind REC tranche will be conducted in 2022.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
|
| | | | | | | | | | | | |
| | | | | | December 31, |
| | | | | 2018 | | 2017 |
| Par Value | | Shares Authorized | | Shares Outstanding |
| Common Stock | | | | | | | |
| Exelon | no par value |
| | 2,000,000,000 |
| | 968,187,955 |
| | 963,335,888 |
|
| ComEd | $ | 12.50 |
| | 250,000,000 |
| | 127,021,331 |
| | 127,021,246 |
|
| PECO | no par value |
| | 500,000,000 |
| | 170,478,507 |
| | 170,478,507 |
|
| BGE | no par value |
| | 1,500 |
| | 1,000 |
| | 1,000 |
|
| Pepco | $ | 0.01 |
| | 200,000,000 |
| | 100 |
| | 100 |
|
| DPL | $ | 2.25 |
| | 1,000 |
| | 1,000 |
| | 1,000 |
|
| ACE | $ | 3.00 |
| | 25,000,000 |
| | 8,546,017 |
| | 8,546,017 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expiration within |
| Exelon | Total | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 and beyond |
| Letters of credit | $ | 1,243 | | | $ | 1,179 | | | $ | 50 | | | $ | 14 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Surety bonds(a) | 1,070 | | | 1,017 | | | 53 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Financing trust guarantees | 378 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 378 | |
Guaranteed lease residual values(b) | 28 | | | 2 | | | 3 | | | 3 | | | 6 | | | 5 | | | 9 | |
| Total commercial commitments | $ | 2,719 | | | $ | 2,198 | | | $ | 106 | | | $ | 17 | | | $ | 6 | | | $ | 5 | | | $ | 387 | |
| | | | | | | | | | | | | |
| Generation | | | | | | | | | | | | | |
| Letters of credit | $ | 1,228 | | | $ | 1,164 | | | $ | 50 | | | $ | 14 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Surety bonds(a) | 926 | | | 873 | | | 53 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total commercial commitments | $ | 2,154 | | | $ | 2,037 | | | $ | 103 | | | $ | 14 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | |
| ComEd | | | | | | | | | | | | | |
| Letters of credit | $ | 7 | | | $ | 7 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Surety bonds(a) | 16 | | | 16 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Financing trust guarantees | 200 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 200 | |
| Total commercial commitments | $ | 223 | | | $ | 23 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 200 | |
| | | | | | | | | | | | | |
| PECO | | | | | | | | | | | | | |
Surety bonds(a) | $ | 2 | | | $ | 2 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Financing trust guarantees | 178 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 178 | |
| Total commercial commitments | $ | 180 | | | $ | 2 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 178 | |
| | | | | | | | | | | | | |
| BGE | | | | | | | | | | | | | |
| Letters of credit | $ | 2 | | | $ | 2 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Surety bonds(a) | 3 | | | 3 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total commercial commitments | $ | 5 | | | $ | 5 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | |
| PHI | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Surety bonds(a) | $ | 22 | | | $ | 22 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Guaranteed lease residual values(b) | 28 | | | 2 | | | 3 | | | 3 | | | 6 | | | 5 | | | 9 | |
| Total commercial commitments | $ | 50 | | | $ | 24 | | | $ | 3 | | | $ | 3 | | | $ | 6 | | | $ | 5 | | | $ | 9 | |
| | | | | | | | | | | | | |
| Pepco | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Surety bonds(a) | $ | 14 | | | $ | 14 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Guaranteed lease residual values(b) | 9 | | | 0 | | | 1 | | | 1 | | | 2 | | | 2 | | | 3 | |
| Total commercial commitments | $ | 23 | | | $ | 14 | | | $ | 1 | | | $ | 1 | | | $ | 2 | | | $ | 2 | | | $ | 3 | |
| | | | | | | | | | | | | |
| DPL | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Surety bonds(a) | $ | 4 | | | $ | 4 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Guaranteed lease residual values(b) | 12 | | | 1 | | | 1 | | | 1 | | | 3 | | | 2 | | | 4 | |
| Total commercial commitments | $ | 16 | | | $ | 5 | | | $ | 1 | | | $ | 1 | | | $ | 3 | | | $ | 2 | | | $ | 4 | |
| | | | | | | | | | | | | |
| ACE | | | | | | | | | | | | | |
Surety bonds(a) | $ | 4 | | | $ | 4 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Guaranteed lease residual values(b) | 7 | | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | | 2 | |
| Total commercial commitments | $ | 11 | | | $ | 5 | | | $ | 1 | | | $ | 1 | | | $ | 1 | | | $ | 1 | | | $ | 2 | |
__________
(a)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
(b)Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $71 million guaranteed by Exelon and PHI, of which $24 million, $30 million, and $17 million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
Nuclear Insurance (Exelon and Generation)
Generation is subject to liability, property damage, and other risks associated with major incidents at any of its nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.
The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2020, the current liability limit per incident is $13.8 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.3 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Generation’s share of this secondary layer would be approximately $2.9 billion, however any amounts payable under this secondary layer would be capped at $434 million per year.
In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.8 billion limit for a single incident.
As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 23 — Variable Interest Entities for additional information on Generation’s operations relating to CENG.
Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.
NEIL may declare distributions to its members as a result of favorable operating experience. In recent years, NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all. Generation's portion of the annual distribution declared by NEIL is estimated to be $75 million for 2020, and was $136 million and $58 million for 2019 and 2018, respectively. In addition, in March 2018, NEIL declared a supplemental distribution. Generation's portion of the supplemental distribution declared by NEIL was $31 million. The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments, if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $252 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
NEIL provides “all risk” property damage, decontamination, and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by Generation will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity, and any other source, applicable to such losses.
For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial statements.
Spent Nuclear Fuel Obligation (Exelon and Generation)
Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation historically had paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. Due to the lack of a viable disposal program, the DOE reduced the SNF disposal fee to zero in May 2014. Until a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery.
Generation currently assumes the DOE will begin accepting SNF in 2035 and uses that date for purposes of estimating the nuclear decommissioning asset retirement obligations. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage.
The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance is expected to be delayed significantly. In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at Generation’s nuclear stations pending the DOE’s fulfillment of its obligations. Generation’s settlement agreement does not include FitzPatrick and FitzPatrick does not currently have a settlement agreement in place. Calvert Cliffs, Ginna, and Nine Mile Point each have separate settlement agreements in place with the DOE which were extended during 2020 to provide for the reimbursement of SNF storage costs through December 31, 2022. Generation submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.
Under the settlement agreements, Generation received total cumulative cash reimbursements of $1,455 million through December 31, 2020 for costs incurred. After considering the amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek, Generation received net cumulative cash reimbursements of $1,266 million.As of December 31, 2020 and 2019, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
| | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
DOE receivable - current(a) | $ | 129 | | | $ | 249 | |
DOE receivable - noncurrent(b) | 70 | | | 30 | |
Amounts owed to co-owners(c) | (23) | | | (37) | |
__________
(a)Recorded in Accounts receivable, other.
(b)Recorded in Deferred debits and other assets, other.
(c)Recorded in Accounts receivable, other. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.
The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The below table outlines the SNF liability recorded at Exelon and Generation as of December 31, 2020 and 2019:
| | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
Former ComEd units(a) | $ | 1,082 | | | $ | 1,075 | |
Fitzpatrick(b) | 126 | | | 124 | |
| Total SNF Obligation | $ | 1,208 | | | $ | 1,199 | |
__________
(a)ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon’s 2001 corporate restructuring.
(b)A prior owner of FitzPatrick elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, Generation assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation.
Interest for Exelon's and Generation's SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2020 was 0.096% for the deferred amount transferred from ComEd and 0.101% for the deferred FitzPatrick amount.
The following table summarizes sites for which Exelon and Generation do not have an outstanding SNF Obligation:
| | | | | |
| Description | Sites |
| Fees have been paid | Former PECO units, Clinton and Calvert Cliffs |
| Outstanding SNF Obligation remains with former owners | Nine Mile Point, Ginna and TMI |
Environmental Remediation Matters
General (All Registrants).The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies, or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
MGP Sites (Exelon and the Utility Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
•ComEd has 21 sites that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2026.
•PECO has 8 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2023.
•BGE has 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2023.
•DPL has 1 site that is currently under study and the required cost at the site is not expected to be material.
The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.
As of December 31, 2020 and 2019, the Registrants had 60,285accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and 60,584Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Total environmental
investigation and
remediation liabilities | | Portion of total related to
MGP investigation and
remediation | | Total environmental
investigation and
remediation liabilities | | Portion of total related to
MGP investigation and
remediation |
| Exelon | $ | 483 | | | $ | 314 | | | $ | 478 | | | $ | 320 | |
| Generation | 121 | | | 0 | | | 105 | | | 0 | |
| ComEd | 293 | | | 293 | | | 304 | | | 303 | |
| PECO | 23 | | | 21 | | | 19 | | | 17 | |
| BGE | 2 | | | 0 | | | 2 | | | 0 | |
| PHI | 44 | | | 0 | | | 48 | | | 0 | |
| Pepco | 42 | | | 0 | | | 46 | | | 0 | |
| DPL | 1 | | | 0 | | | 1 | | | 0 | |
| ACE | 1 | | | 0 | | | 1 | | | 0 | |
Cotter Corporation (Exelon and Generation).The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.
In September 2018, the EPA issued its Record of Decision (ROD) Amendment for the selection of a final remedy. The ROD Amendment modified the remedy previously selected by EPA in its 2008 ROD. While the 2008 ROD
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
required only that the radiological materials and other wastes at the site be capped, the 2018 ROD Amendment requires partial excavation of the radiological materials in addition to the previously selected capping remedy. The ROD Amendment also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed by early 2022. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Cotter (Generation’s indemnitee) provided a non-binding good faith offer to conduct, or finance, a portion of the remedy, subject to certain conditions. The total estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred collectively by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability, included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial statements.
One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not have sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial statements.
In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation (RI)/Feasibility Study (FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $30 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability, included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood that, or the extent to which any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future financial statements.
In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s (now Generation's) indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until August 31, 2021 so that settlement discussions can proceed. On August 3, 2020, the DOJ advised Cotter and the other PRPs that it is seeking approximately $90 million from all the PRPs and has directed that the PRPs must submit a good faith joint proposed settlement offer. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above.
Benning Road Site (Exelon, Generation, PHI, and Pepco). In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility, which was deactivated in June 2012. The remaining portion of the site consists of a Pepco
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River.
Since 2013, Pepco and Pepco Energy Services (now Generation, pursuant to Exelon's 2016 acquisition of PHI) have been performing RI work and have submitted multiple draft RI reports to the DOEE. In September 2019, Pepco and Generation issued a draft “final” RI report which DOEE approved on February 3, 2020. Pepco and Generation are developing a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the FS, and approval by the DOEE, by September 16, 2021. After completion and approval of the FS, DOEE will prepare a Proposed Plan for public comment and then issue a ROD identifying any further response actions determined to be necessary. PHI, Pepco, and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by Pepco and Generation, DOEE and the National Park Service have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments on the draft RI and participated in a public hearing.
Pepco has determined that it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management’s best estimate of its share of those costs. On September 30, 2020, DOEE released its Interim ROD. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a Natural Resources Damages (NRD) assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, Pepco cannot reasonably estimate the range of loss.
Litigation and Regulatory Matters
Asbestos Personal Injury Claims (Exelon and Generation). Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.
At December 31, 2020 and 2019, Exelon and Generation recorded estimated liabilities of approximately $89 million and $83 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2020, approximately $25 million of this amount related to 261 open claims presented to Generation, while the remaining $64 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.
It is reasonably possible that additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued could have a material, unfavorable impact on Exelon’s and Generation’s financial statements. However, management cannot reasonably estimate a range of loss beyond the amounts recorded.
Fund Transfer Restrictions (All Registrants). Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.
Under applicable law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to Exelon.
ComEd has agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.
Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the DPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.
City of Everett Tax Increment Financing Agreement (Exelon and Generation). On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. On January 8, 2020, the Massachusetts Superior Court affirmed the decision of the EACC denying the City's petition. The City had until March 9, 2020 to appeal the decision and did not. As a result, the decision is final and the case is resolved. It is reasonably possible that property taxes assessed in future periods, including those following the expiration of the TIF Agreement on June 30, 2020, could be material to Generation’s financial statements.
Deferred Prosecution Agreement (DPA) and Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the U.S. Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date. The payments were recorded within Operating and maintenance expense in Exelon’s and ComEd’s Consolidated Statements of Operations and Comprehensive Income in the second quarter of 2020. The payments will not be recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. Exelon made equity contributions to ComEd of $200 million in 2020. On August 13, 2020, a motion was filed in the U.S. District Court for the Northern District of Illinois by a ComEd customer and on behalf of ComEd customers seeking to enjoin ComEd from paying these funds to the U.S. Treasury and requiring the U.S. government to establish a victims’ restitution fund from which the $200 million would be disbursed to ComEd customers. The motion was denied without prejudice on November 6, 2020 and ComEd submitted the $200 million payment to the U.S. Treasury. On January 6, 2021, the customer petitioned the Seventh Circuit for a writ of mandamus to seek review of the district court’s ruling, but on January 8, 2021, the Seventh Circuit denied the petition. On January 22, 2021, the customer petitioned the Seventh Circuit for rehearing of its denial of his petition for a writ of mandamus. On February 5, 2021, the Seventh Circuit denied the petition for rehearing.
Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon.
The SEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the SEC. Exelon and ComEd cannot predict the outcome of the SEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with respect to the SEC investigation, as this contingency is neither probable nor reasonably estimable at this time.
Subsequent to Exelon announcing the receipt of the subpoenas, various lawsuits have been filed and various demand letters have been received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:
•A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. Briefing was completed on February 17, 2021.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
•A derivative shareholder lawsuit was filed against Exelon, its directors and certain officers of Exelon and ComEd in April 2020 alleging, among other things, breaches of fiduciary duties also purporting to relate to matters that are the subject of the subpoenas and the SEC investigation. The plaintiff voluntarily dismissed this derivative action without prejudice to refile on July 28, 2020.
•Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. These three state cases were consolidated into a single action in October of 2020. In addition, on November 2, 2020, the Citizens Utility Board (CUB) filed a motion to intervene in the state cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November 23, 2020, the court allowed CUB’s intervention, but denied CUB’s request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion is ongoing.
•Four putative class action lawsuits against ComEd and Exelon were filed in federal court in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, CUB filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. In addition, on December 2, 2020, the court appointed interim lead plaintiffs in the federal cases which consisted of counsel for three of the four federal cases. These plaintiffs filed a consolidated complaint on January 5, 2021. CUB also filed its own complaint against ComEd only on the same day. The remaining federal case, Potter, et al. v. Exelon et al, differed from the other lawsuits as it named additional individual defendants not named in the consolidated complaint. On January 10, 2021, the Potter plaintiffs filed a motion asking the court to clarify that their class action complaint against ComEd, Exelon and the individual named defendants remains in effect, notwithstanding the consolidated amended complaint, and asked the court to stay the Potter case. On January 21, 2021, the court determined that the appointed lead counsel had sole discretion to determine which parties to name as plaintiffs and defendants, and that the Potter plaintiffs have the option to opt-out of that class and file a separate, individual action against the defendants named in their original complaint. The Potter plaintiffs have until March 23, 2021 to make that decision.
•Four shareholders sent letters to the Exelon Board of Directors in 2020 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA.
No loss contingencies have been reflected in Exelon’s and ComEd’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.
General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
20. Shareholders' Equity (Exelon and Utility Registrants)
ComEd Common Stock Warrants
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 20 — Shareholders' Equity
The following table presents warrants outstanding to purchase ComEd common stock at December 31, 2018 and 2017, respectively.shares of common stock reserved for the conversion of warrants. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. At December 31, 2018 and 2017, 20,095 and 20,195 shares of common stock, respectively, were reserved for the conversion of warrants.
Equity Securities Offering | | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 |
| Warrants outstanding | 60,143 | | | 60,228 | |
| Common Stock reserved for conversion | 20,048 | | | 20,076 | |
In June 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share. In connection with such offering, Exelon entered into forward sale agreements with two counterparties. In July 2015, Exelon settled the forward sale agreement by the issuance of 57.5 million shares of Exelon common stock. Exelon received net cash proceeds of $1.87 billion, which was calculated based on a forward price of $32.48 per share as specified in the forward sale agreements. The net proceeds were used to fund the merger with PHI and related costs and expenses, and for general corporate purposes. The forward sale agreements are classified as equity transactions. As a result, no amounts were recorded in the consolidated financial statements until the July 2015 settlement of the forward sale agreements. However, prior to the July 2015 settlement, incremental shares, if any, were included within the calculation of diluted EPS using the treasury stock method.
Concurrent with the forward equity transaction, Exelon also issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. On June 1, 2017, Exelon settled the forward purchase contract, which was a component of the June 2014 equity units, through the issuance of Exelon common stock from treasury stock. See Note 13 — Debt and Credit Agreements for additional information on the equity units.
Share Repurchases
Share Repurchase Programs
There currently is no0 Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management. Under the previous share repurchase programs, 2 million shares of common stock were held as treasury stock with a historical cost of $123 million at December 31, 2018 and 2017. During 2017, Exelon issued approximately 33 million shares of Exelon common stock from treasury stock in order to settle the forward purchase contract, which was a component of the June 2014 equity units discussed above. During 2018, 2017, and 2016 Exelon had no common stock repurchases.
Preferred and Preference Securities of Subsidiaries
At December 31, 2018The following table presents Exelon, ComEd, PECO, BGE, Pepco, and 2017, Exelon was authorized to issue up to 100,000,000ACE's shares of preferred securities noneauthorized, NaN of which were outstanding.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Atoutstanding as of December 31, 20182020 and 2017, ComEd prior2019. There are 0 shares of preferred securities authorized for DPL.
| | | | | |
| Preferred Securities Authorized |
| Exelon | 100,000,000 | |
| ComEd | 850,000 | |
| PECO | 15,000,000 | |
| BGE | 1,000,000 | |
| Pepco | 6,000,000 | |
ACE(a) | 2,799,979 | |
__________
(a)Includes 799,979 shares of cumulative preferred stock and ComEd cumulative2,000,000 of no-par preferred stock as of December 31, 2020 and 2019.
The following table presents ComEd's, BGE's, and ACE's preference securities consisted of 850,000 shares and 6,810,451 shares authorized, respectively, noneNaN of which were outstanding.
BGE had $190 millionoutstanding as of cumulative preference stock that was redeemable at its option at any time after October 1, 2015 for the redemption price of $100 per share, plus accruedDecember 31, 2020 and unpaid dividends. On July 3, 2016, BGE redeemed all 400,0002019. There are 0 shares of its outstanding 7.125% Cumulative Preference Stock, 1993 Seriespreference securities authorized for Exelon, PECO, Pepco, and all 600,000DPL.
| | | | | |
| Preference Securities Authorized |
| ComEd | 6,810,451 | |
BGE(a) | 6,500,000 | |
| ACE | 3,000,000 | |
__________
(a)Includes 4,600,000 shares of its outstanding 6.990% Cumulative Preference Stock, 1995 Series for $100 million, plus accruedunclassified preference securities and unpaid dividends. On September 18, 2016, BGE redeemed the remaining 500,0001,900,000 shares of its outstanding 6.970% Cumulative Preference Stock, 1993 Seriespreviously redeemed preference securities as of December 31, 2020 and the remaining 400,000 shares of its outstanding 6.700% Cumulative Preference Stock, 1993 Series for $90 million, plus accrued and unpaid dividends.2019.
19.
21. Stock-Based Compensation Plans (All Registrants)
Stock-Based Compensation Plans
Exelon grants stock-based awards through its LTIP, which primarily includes stock options,performance share awards, restricted stock units, and performance share awards.stock options. At December 31, 2018,2020, there were approximately 1134 million shares authorized for issuance under the LTIP. For the years ended December 31, 2018, 20172020, 2019, and 2016,2018, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.
ComEd, PECO, BGE and PHIThe Registrants grant cash awards. The following tables dotable does not include expense related to these plans as they are not considered stock-based compensation plans under the applicable authoritative guidance.
In connection with the acquisition of PHI in March 2016, PHI’s unvested time-based restricted stock units and performance-based restricted stock units issued prior to April 29, 2014 were immediately vested and paid in cash upon the close of the merger. PHI’s remaining unvested time-based restricted stock units as of the close of the merger were cancelled. There were no remaining unvested performance-based restricted stock units as of the close of the merger.
For the years ended December 31, 2018, 2017 and 2016, there were no significant modifications to the granted stock based awards.
The following tables present the stock-based compensation expense included in Exelon's and PHI’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2018, 2017 and 2016 and PHI's predecessor period January 1, 2016 to March 23, 2016:guidance.
|
| | | | | | | | | | | |
| Exelon | Year Ended December 31, |
| Components of Stock-Based Compensation Expense | 2018 | | 2017 | | 2016(a) |
| Performance share awards | $ | 143 |
| | $ | 107 |
| | $ | 93 |
|
| Restricted stock units | 57 |
| | 77 |
| | 75 |
|
| Stock options | — |
| | — |
| | — |
|
| Other stock-based awards | 8 |
| | 7 |
| | 7 |
|
| Total stock-based compensation expense included in operating and maintenance expense | 208 |
| | 191 |
| | 175 |
|
| Income tax benefit | (54 | ) | | (74 | ) | | (68 | ) |
| Total after-tax stock-based compensation expense | $ | 154 |
| | $ | 117 |
| | $ | 107 |
|
__________
| |
(a) | 2016 amounts include expense related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 21 — Stock-Based Compensation Plans
PHI
|
| | | |
| | Predecessor |
| | January 1 to March 23, |
| Components of Stock-Based Compensation Expense | 2016 |
| Time-based restricted stock units | $ | 2 |
|
| Performance-based restricted stock units | 1 |
|
| Time-based restricted stock awards | — |
|
Total stock-based compensation expense included in operating and maintenance expense | 3 |
|
| Income tax benefit | (1 | ) |
| Total after-tax stock-based compensation expense | $ | 2 |
|
The following tables presenttable presents the stock-based compensation expense included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The Utility Registrants' stock-based compensation expense (pre-tax) for the years ended December 31, 2020, 2019, and 2018 2017 and 2016, as well as for the PHI predecessor period January 1, 2016 to March 23, 2016:was not material.
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| Subsidiaries | 2018 | | 2017 | | 2016 |
| Exelon | $ | 208 |
| | $ | 191 |
| | $ | 175 |
|
| Generation | 77 |
| | 88 |
| | 78 |
|
| ComEd | 8 |
| | 7 |
| | 8 |
|
| PECO | 5 |
| | 3 |
| | 3 |
|
| BGE | 3 |
| | 1 |
| | 1 |
|
BSC(a) | 111 |
| | 88 |
| | 81 |
|
PHI Successor(b)(c) | 4 |
| | 4 |
| | 4 |
|
|
| | | |
| | Predecessor |
| | January 1 to
March 23, |
| | 2016 |
| PHI | $ | 3 |
|
__________
| |
(a) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE or PHI amounts above. |
| |
(b) | Pepco's, DPL's and ACE's stock-based compensation expense for the years ended December 31, 2018 and 2017 was not material. |
| |
(c) | These amounts primarily represent amounts billed to PHI’s subsidiaries through PHISCO intercompany allocations.
|
There were no significant stock-based compensation costs capitalized during the years ended December 31, 2018, 2017 and 2016 for Exelon or PHI, or for PHI during the predecessor period January 1, 2016 to March 23, 2016.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| Exelon | 2020 | | 2019 | | 2018 |
| Total stock-based compensation expense included in operating and maintenance expense | $ | 64 | | | $ | 77 | | | $ | 208 | |
| Income tax benefit | (16) | | | (20) | | | (54) | |
| Total after-tax stock-based compensation expense | $ | 48 | | | $ | 57 | | | $ | 154 | |
| Generation | | | | | |
| Total stock-based compensation expense included in operating and maintenance expense | $ | 27 | | | $ | 37 | | | $ | 77 | |
| Income tax benefit | (7) | | | (10) | | | (20) | |
| Total after-tax stock-based compensation expense | $ | 20 | | | $ | 27 | | | $ | 57 | |
Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The following tables presenttable presents information regarding Exelon’s realized tax benefits for the years ended December 31, 2018, 2017 and 2016.benefit when distributed:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| Performance share awards | $ | 21 | | | $ | 41 | | | $ | 16 | |
| Restricted stock units | 15 | | | 24 | | | 28 | |
|
| | | | | | | | |
| Exelon | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Realized tax benefit when exercised/distributed: | | | | | |
| Restricted stock units | 28 |
| | 35 |
| | 27 |
|
| Performance share awards | 16 |
| | 29 |
| | 18 |
|
Stock Options
Non-qualified stock options to purchase shares of Exelon’s common stock werePerformance share awards are granted under the LTIP through 2012. DueLTIP. The performance share awards are settled 50% in common stock and 50% in cash at the end of the three-year performance period, except for awards granted to vice presidents and higher officers that are settled 100% in cash if certain ownership requirements are satisfied.
The common stock portion of the performance share awards is considered an equity award and is valued based on Exelon's stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the LTIP, there were no stock options granted in 2018, 2017total shareholder return modifier and 2016. For all stock options granted through 2012, the exercise priceexpected payout of the stock optionsaward, the compensation costs are subject to volatility until payout is equal toestablished.
For nonretirement-eligible employees, stock-based compensation costs are recognized over the fair market value of the underlying stock on the date of option grant. The vesting period of stock options is generally fourthree years and all stock options will expire no later than ten years from the date of grant.
The value of stock options at the date of grant is expensed over the requisite service period using the straight-line method. The requisite service period for stock options is generally four years. However, certain stock options become fully vested upon the employee reaching retirement-eligibility. The value of the stock optionsFor performance share awards granted to retirement-eligible employees, the value of the performance shares is either recognized immediately uponratably over the date of grant or through the date atvesting period, which the employee reaches retirement eligibility.
The following table presents information with respect to stock option activity foris the year ended December 31, 2018:of grant.
Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
|
| | | | | | | | | | | | |
| | Shares | | Weighted Average Exercise Price (per share) | | Weighted Average Remaining Contractual Life (years) | | Aggregate Intrinsic Value |
| Balance of shares outstanding at December 31, 2017 | 6,723,611 |
| | $ | 47.69 |
| | 2.65 | | $ | 7 |
|
| Options exercised | (1,522,952 | ) | | 36.54 |
| | | | |
| Options forfeited | — |
| | — |
| | | | |
| Options expired | (1,173,007 | ) | | 74.99 |
| | | | |
| Balance of shares outstanding at December 31, 2018 | 4,027,652 |
| | $ | 43.95 |
| | 2.90 | | $ | 14 |
|
Exercisable at December 31, 2018 (a) | 4,027,652 |
| | $ | 43.95 |
| | 2.90 | | $ | 14 |
|
__________
| |
(a) | Includes stock options issued to retirement eligible employees. |
The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2018, 2017 and 2016:Exelon’s nonvested performance share awards activity:
|
| | | | | | | | | | | |
| | Year Ended
December 31, |
| | 2018 | | 2017 | | 2016 |
Intrinsic value(a) | $ | 12 |
| | $ | 15 |
| | $ | 11 |
|
| Cash received for exercise price | 56 |
| | 107 |
| | 19 |
|
__________
| |
(a) | The difference between the market value on the date of exercise and the option exercise price. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 21 — Stock-Based Compensation Plans
At | | | | | | | | | | | |
| Shares | | Weighted Average
Grant Date Fair
Value (per share) |
Nonvested at December 31, 2019(a) | 1,709,755 | | | $ | 39.21 | |
| Granted | 1,122,378 | | | 46.61 | |
| Change in performance | (751,309) | | | 42.51 | |
| Vested | (747,551) | | | 35.70 | |
| Forfeited | (67,964) | | | 45.59 | |
Undistributed vested awards(b) | (334,917) | | | 50.76 | |
Nonvested at December 31, 2020(a) | 930,392 | | | $ | 43.67 | |
__________
(a)Excludes 1,414,661 and 2,017,870 of performance share awards issued to retirement-eligible employees as of December 31, 2016, all stock options2020 and 2019, respectively, as they are fully vested.
(b)Represents performance share awards that vested but were vestednot distributed to retirement-eligible employees during 2020.
The following table summarizes the weighted average grant date fair value and atthe total fair value of performance share awards vested.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020(a) | | 2019 | | 2018 |
| Weighted average grant date fair value (per share) | $ | 46.61 | | | $ | 47.37 | | | $ | 38.15 | |
| Total fair value of performance shares vested | 39 | | | 158 | | | 61 | |
| Total fair value of performance shares settled in cash | 63 | | | 131 | | | 49 | |
__________
(a)As of December 31, 2018 there were no2020, $13 million of total unrecognized compensation costs related to nonvested stock options.performance shares are expected to be recognized over the remaining weighted-average period of 1.8 years.
Restricted Stock UnitsEnvironmental Remediation Matters
RestrictedGeneral (All Registrants).The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies, or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
MGP Sites (Exelon and the Utility Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
•ComEd has 21 sites that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2026.
•PECO has 8 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2023.
•BGE has 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2023.
•DPL has 1 site that is currently under study and the required cost at the site is not expected to be material.
The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.
As of December 31, 2020 and 2019, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Total environmental
investigation and
remediation liabilities | | Portion of total related to
MGP investigation and
remediation | | Total environmental
investigation and
remediation liabilities | | Portion of total related to
MGP investigation and
remediation |
| Exelon | $ | 483 | | | $ | 314 | | | $ | 478 | | | $ | 320 | |
| Generation | 121 | | | 0 | | | 105 | | | 0 | |
| ComEd | 293 | | | 293 | | | 304 | | | 303 | |
| PECO | 23 | | | 21 | | | 19 | | | 17 | |
| BGE | 2 | | | 0 | | | 2 | | | 0 | |
| PHI | 44 | | | 0 | | | 48 | | | 0 | |
| Pepco | 42 | | | 0 | | | 46 | | | 0 | |
| DPL | 1 | | | 0 | | | 1 | | | 0 | |
| ACE | 1 | | | 0 | | | 1 | | | 0 | |
Cotter Corporation (Exelon and Generation).The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.
In September 2018, the EPA issued its Record of Decision (ROD) Amendment for the selection of a final remedy. The ROD Amendment modified the remedy previously selected by EPA in its 2008 ROD. While the 2008 ROD
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
required only that the radiological materials and other wastes at the site be capped, the 2018 ROD Amendment requires partial excavation of the radiological materials in addition to the previously selected capping remedy. The ROD Amendment also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed by early 2022. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Cotter (Generation’s indemnitee) provided a non-binding good faith offer to conduct, or finance, a portion of the remedy, subject to certain conditions. The total estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred collectively by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability, included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial statements.
One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not have sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial statements.
In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation (RI)/Feasibility Study (FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $30 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability, included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood that, or the extent to which any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future financial statements.
In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s (now Generation's) indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until August 31, 2021 so that settlement discussions can proceed. On August 3, 2020, the DOJ advised Cotter and the other PRPs that it is seeking approximately $90 million from all the PRPs and has directed that the PRPs must submit a good faith joint proposed settlement offer. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above.
Benning Road Site (Exelon, Generation, PHI, and Pepco). In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility, which was deactivated in June 2012. The remaining portion of the site consists of a Pepco
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River.
Since 2013, Pepco and Pepco Energy Services (now Generation, pursuant to Exelon's 2016 acquisition of PHI) have been performing RI work and have submitted multiple draft RI reports to the DOEE. In September 2019, Pepco and Generation issued a draft “final” RI report which DOEE approved on February 3, 2020. Pepco and Generation are developing a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the FS, and approval by the DOEE, by September 16, 2021. After completion and approval of the FS, DOEE will prepare a Proposed Plan for public comment and then issue a ROD identifying any further response actions determined to be necessary. PHI, Pepco, and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by Pepco and Generation, DOEE and the National Park Service have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments on the draft RI and participated in a public hearing.
Pepco has determined that it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management’s best estimate of its share of those costs. On September 30, 2020, DOEE released its Interim ROD. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a Natural Resources Damages (NRD) assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, Pepco cannot reasonably estimate the range of loss.
Litigation and Regulatory Matters
Asbestos Personal Injury Claims (Exelon and Generation). Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.
At December 31, 2020 and 2019, Exelon and Generation recorded estimated liabilities of approximately $89 million and $83 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2020, approximately $25 million of this amount related to 261 open claims presented to Generation, while the remaining $64 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.
It is reasonably possible that additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued could have a material, unfavorable impact on Exelon’s and Generation’s financial statements. However, management cannot reasonably estimate a range of loss beyond the amounts recorded.
Fund Transfer Restrictions (All Registrants). Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.
Under applicable law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to Exelon.
ComEd has agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock units are grantedin the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the LTIPIndenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.
Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the DPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.
City of Everett Tax Increment Financing Agreement (Exelon and Generation). On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. On January 8, 2020, the Massachusetts Superior Court affirmed the decision of the EACC denying the City's petition. The City had until March 9, 2020 to appeal the decision and did not. As a result, the decision is final and the case is resolved. It is reasonably possible that property taxes assessed in future periods, including those following the expiration of the TIF Agreement on June 30, 2020, could be material to Generation’s financial statements.
Deferred Prosecution Agreement (DPA) and Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a DPA with the majorityUSAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the U.S. Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date. The payments were recorded within Operating and maintenance expense in Exelon’s and ComEd’s Consolidated Statements of Operations and Comprehensive Income in the second quarter of 2020. The payments will not be recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. Exelon made equity contributions to ComEd of $200 million in 2020. On August 13, 2020, a motion was filed in the U.S. District Court for the Northern District of Illinois by a ComEd customer and on behalf of ComEd customers seeking to enjoin ComEd from paying these funds to the U.S. Treasury and requiring the U.S. government to establish a victims’ restitution fund from which the $200 million would be disbursed to ComEd customers. The motion was denied without prejudice on November 6, 2020 and ComEd submitted the $200 million payment to the U.S. Treasury. On January 6, 2021, the customer petitioned the Seventh Circuit for a writ of mandamus to seek review of the district court’s ruling, but on January 8, 2021, the Seventh Circuit denied the petition. On January 22, 2021, the customer petitioned the Seventh Circuit for rehearing of its denial of his petition for a writ of mandamus. On February 5, 2021, the Seventh Circuit denied the petition for rehearing.
Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended with no charges being settledbrought against Exelon.
The SEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the SEC. Exelon and ComEd cannot predict the outcome of the SEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with respect to the SEC investigation, as this contingency is neither probable nor reasonably estimable at this time.
Subsequent to Exelon announcing the receipt of the subpoenas, various lawsuits have been filed and various demand letters have been received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:
•A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a specific numbermotion to dismiss in November 2020. Briefing was completed on February 17, 2021.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
•A derivative shareholder lawsuit was filed against Exelon, its directors and certain officers of Exelon and ComEd in April 2020 alleging, among other things, breaches of fiduciary duties also purporting to relate to matters that are the subject of the subpoenas and the SEC investigation. The plaintiff voluntarily dismissed this derivative action without prejudice to refile on July 28, 2020.
•Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. These three state cases were consolidated into a single action in October of 2020. In addition, on November 2, 2020, the Citizens Utility Board (CUB) filed a motion to intervene in the state cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November 23, 2020, the court allowed CUB’s intervention, but denied CUB’s request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion is ongoing.
•Four putative class action lawsuits against ComEd and Exelon were filed in federal court in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, CUB filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. In addition, on December 2, 2020, the court appointed interim lead plaintiffs in the federal cases which consisted of counsel for three of the four federal cases. These plaintiffs filed a consolidated complaint on January 5, 2021. CUB also filed its own complaint against ComEd only on the same day. The remaining federal case, Potter, et al. v. Exelon et al, differed from the other lawsuits as it named additional individual defendants not named in the consolidated complaint. On January 10, 2021, the Potter plaintiffs filed a motion asking the court to clarify that their class action complaint against ComEd, Exelon and the individual named defendants remains in effect, notwithstanding the consolidated amended complaint, and asked the court to stay the Potter case. On January 21, 2021, the court determined that the appointed lead counsel had sole discretion to determine which parties to name as plaintiffs and defendants, and that the Potter plaintiffs have the option to opt-out of that class and file a separate, individual action against the defendants named in their original complaint. The Potter plaintiffs have until March 23, 2021 to make that decision.
•Four shareholders sent letters to the Exelon Board of Directors in 2020 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA.
No loss contingencies have been reflected in Exelon’s and ComEd’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.
General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
20. Shareholders' Equity (Exelon and Utility Registrants)
ComEd Common Stock Warrants
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 20 — Shareholders' Equity
The following table presents warrants outstanding to purchase ComEd common stock and shares of common stock afterreserved for the service condition has been met.conversion of warrants. The correspondingwarrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants.
| | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 |
| Warrants outstanding | 60,143 | | | 60,228 | |
| Common Stock reserved for conversion | 20,048 | | | 20,076 | |
Share Repurchases
There currently is 0 Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of services is measured based on the grant date fair value of the restricted stock unit issued.Exelon’s management.
The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.Preferred and Preference Securities
The following table summarizes Exelon’s nonvestedpresents Exelon, ComEd, PECO, BGE, Pepco, and ACE's shares of preferred securities authorized, NaN of which were outstanding as of December 31, 2020 and 2019. There are 0 shares of preferred securities authorized for DPL.
| | | | | |
| Preferred Securities Authorized |
| Exelon | 100,000,000 | |
| ComEd | 850,000 | |
| PECO | 15,000,000 | |
| BGE | 1,000,000 | |
| Pepco | 6,000,000 | |
ACE(a) | 2,799,979 | |
__________
(a)Includes 799,979 shares of cumulative preferred stock and 2,000,000 of no-par preferred stock as of December 31, 2020 and 2019.
The following table presents ComEd's, BGE's, and ACE's preference securities authorized, NaN of which were outstanding as of December 31, 2020 and 2019. There are 0 shares of preference securities authorized for Exelon, PECO, Pepco, and DPL.
| | | | | |
| Preference Securities Authorized |
| ComEd | 6,810,451 | |
BGE(a) | 6,500,000 | |
| ACE | 3,000,000 | |
__________
(a)Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2020 and 2019.
21. Stock-Based Compensation Plans (All Registrants)
Stock-Based Compensation Plans
Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards, restricted stock unit activityunits, and stock options. At December 31, 2020, there were approximately 34 million shares authorized for issuance under the yearLTIP. For the years ended December 31, 2018:2020, 2019, and 2018, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.
ExelonThe Registrants grant cash awards. The following table does not include expense related to these plans as they are not considered stock-based compensation plans under the applicable authoritative guidance.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 21 — Stock-Based Compensation Plans
|
| | | | | | |
| | Shares | | Weighted Average Grant Date Fair Value (per share) |
Nonvested at December 31, 2017(a) | 3,389,503 |
| | $ | 32.24 |
|
| Granted | 1,321,988 |
| | 38.60 |
|
| Vested | (1,845,300 | ) | | 32.03 |
|
| Forfeited | (65,046 | ) | | 32.96 |
|
Undistributed vested awards (b) | (507,804 | ) | | 36.76 |
|
Nonvested at December 31, 2018(a) | 2,293,341 |
| | $ | 35.06 |
|
__________
| |
(a) | Excludes 1,131,487 and 1,488,383 of restricted stock units issued to retirement-eligible employees as of December 31, 2018 and 2017, respectively, as they are fully vested. |
| |
(b) | Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2018. |
For Exelon,The following table presents the weighted average grant date fair value (per share)stock-based compensation expense included in Exelon's and Generation's Consolidated Statements of restricted stock units grantedOperations and Comprehensive Income. The Utility Registrants' stock-based compensation expense for the years ended December 31, 2020, 2019, and 2018 2017was not material.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| Exelon | 2020 | | 2019 | | 2018 |
| Total stock-based compensation expense included in operating and maintenance expense | $ | 64 | | | $ | 77 | | | $ | 208 | |
| Income tax benefit | (16) | | | (20) | | | (54) | |
| Total after-tax stock-based compensation expense | $ | 48 | | | $ | 57 | | | $ | 154 | |
| Generation | | | | | |
| Total stock-based compensation expense included in operating and maintenance expense | $ | 27 | | | $ | 37 | | | $ | 77 | |
| Income tax benefit | (7) | | | (10) | | | (20) | |
| Total after-tax stock-based compensation expense | $ | 20 | | | $ | 27 | | | $ | 57 | |
Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and 2016 was $38.60, $34.98the distribution date for performance share awards and $28.14, respectively. At December 31, 2018 and 2017,restricted stock units. For each award, throughout the requisite service period, Exelon had obligationsrecognizes the tax benefit related to outstanding restricted stock units not yet settled of $83 million and $108 million, respectively, which are included in common stock incompensation costs. The following table presents information regarding Exelon’s Consolidated Balance Sheets. For the years ended December 31, 2018, 2017 and 2016, Exelon settled restricted stock units with fair value totaling $106 million, $88 million and $68 million, respectively. At December 31, 2018, $38 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.5 years.realized tax benefit when distributed:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| Performance share awards | $ | 21 | | | $ | 41 | | | $ | 16 | |
| Restricted stock units | 15 | | | 24 | | | 28 | |
Performance Share Awards
Performance share awards are granted under the LTIP. The performance share awards are settled 50% in common stock and 50% in cash at the end of the three-year performance period, except for awards granted to vice presidents and higher officers that are settled 100% in cash if certain ownership requirements are satisfied.
The common stock portion of the performance share awards is considered an equity award and is valued based on Exelon's stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Effective January 2017 forFor nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant.
In 2016 and prior, for nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant.
Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
The following table summarizes Exelon’s nonvested performance share awards activity for the year endedactivity:
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 21 — Stock-Based Compensation Plans
| | | | | | | | | | | |
| Shares | | Weighted Average
Grant Date Fair
Value (per share) |
Nonvested at December 31, 2019(a) | 1,709,755 | | | $ | 39.21 | |
| Granted | 1,122,378 | | | 46.61 | |
| Change in performance | (751,309) | | | 42.51 | |
| Vested | (747,551) | | | 35.70 | |
| Forfeited | (67,964) | | | 45.59 | |
Undistributed vested awards(b) | (334,917) | | | 50.76 | |
Nonvested at December 31, 2020(a) | 930,392 | | | $ | 43.67 | |
__________
(a)Excludes 1,414,661 and 2,017,870 of performance share awards issued to retirement-eligible employees as of December 31, 2018:2020 and 2019, respectively, as they are fully vested.
Exelon(b)Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2020.
|
| | | | | | |
| | Shares | | Weighted Average Grant Date Fair Value (per share) |
Nonvested at December 31, 2017(a) | 2,956,966 |
| | $ | 32.65 |
|
| Granted | 1,637,542 |
| | 38.15 |
|
| Change in performance | 1,348,029 |
| | 30.66 |
|
| Vested | (848,574 | ) | | 36.26 |
|
| Forfeited | (50,467 | ) | | 36.24 |
|
Undistributed vested awards (b) | (1,640,268 | ) | | 33.38 |
|
Nonvested at December 31, 2018(a) | 3,403,228 |
| | $ | 33.13 |
|
__________
| |
(a) | Excludes 3,586,259 and 2,723,440 of performance share awards issued to retirement-eligible employees as of December 31, 2018 and 2017, respectively, as they are fully vested. |
| |
(b) | Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2018. |
The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards granted and settled for the years ended December 31, 2018, 2017 and 2016:vested.
|
| | | | | | | | | | | |
| | Year Ended
December 31, |
| | 2018(a) | | 2017 | | 2016 |
| Weighted average grant date fair value (per share) | $ | 38.15 |
| | $ | 35.00 |
| | $ | 28.85 |
|
| Fair value of performance shares settled | 61 |
| | 72 |
| | 45 |
|
| Fair value of performance shares settled in cash | 49 |
| | 56 |
| | 28 |
|
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020(a) | | 2019 | | 2018 |
| Weighted average grant date fair value (per share) | $ | 46.61 | | | $ | 47.37 | | | $ | 38.15 | |
| Total fair value of performance shares vested | 39 | | | 158 | | | 61 | |
| Total fair value of performance shares settled in cash | 63 | | | 131 | | | 49 | |
__________
| |
(a) | As of December 31, 2018, $33 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.7 years. |
For PHI, the weighted average grant date fair value (per share) of performance-based restricted stock awards was $26.10 for the year ended December 31, 2016. There were no time-based restricted stock awards granted for the year ended December 31, 2016. There were no time-based share settlements or performance-based share settlements for the year-ended December 31, 2016 or the predecessor period January 1, 2016 to March 23, 2016.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
Current liabilities(a) | $ | 135 |
| | $ | 57 |
|
Deferred credits and other liabilities(b) | 109 |
| | 100 |
|
| Common stock | 26 |
| | 26 |
|
| Total | $ | 270 |
| | $ | 183 |
|
__________
| |
(a) | Represents the current liability related to performance share awards expected to be settled in cash. |
| |
(b) | Represents the long-term liability related to performance share awards expected to be settled in cash. |
20. Earnings Per Share (Exelon)
Basic earnings per share is computed by dividing net income attributable to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income attributable to common shareholders by the weighted average number of common shares outstanding, including the effect of issuing common stock assuming (i) stock options are exercised, and (ii) performance share awards and restricted stock awards are fully vested under the treasury stock method.
The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock awards on the weighted average number of shares outstanding used in calculating diluted earnings per share:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Net income attributable to common shareholders | $ | 2,010 |
|
| $ | 3,786 |
|
| $ | 1,121 |
|
| Weighted average common shares outstanding — basic | 967 |
|
| 947 |
|
| 924 |
|
| Assumed exercise and/or distributions of stock-based awards | 2 |
| | 2 |
| | 3 |
|
| Weighted average common shares outstanding — diluted | 969 |
|
| 949 |
|
| 927 |
|
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 3 million in 2018, 8 million in 2017, and 12 million in 2016. There were no equity units related to the PHI merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect for the years ended December 31, 2018, 2017, and 2016. See Note 18 — Shareholders' Equity for additional information regarding the equity units and equity forward units.
On June 1, 2017, Exelon settled the forward purchase contract, which was a component of the June 2014 equity units, through the issuance of approximately 33 million shares of Exelon common stock from treasury stock. The issuance of shares on June 1, 2017 triggered full dilution in the EPS calculation, which prior to settlement were included in the calculation of diluted EPS using the treasury stock method. See Note 18 — Shareholders' Equity for additional information regarding share repurchases.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
21. Changes in Accumulated Other Comprehensive Income (Exelon, Generation and PECO)
The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2018 and 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2018 | Gains and
(Losses) on
Cash Flow
Hedges |
| Unrealized
Gains and (losses) on
Marketable
Securities |
| Pension and
Non-Pension
Postretirement
Benefit Plan
Items |
| Foreign
Currency
Items |
| AOCI of Investments
Unconsolidated
Affiliates |
| Total |
Exelon(a) |
|
|
|
|
|
|
|
|
|
|
|
| Beginning balance | $ | (14 | ) | | $ | 10 |
| | $ | (2,998 | ) | | $ | (23 | ) | | $ | (1 | ) | | $ | (3,026 | ) |
| OCI before reclassifications | 11 |
| | — |
| | (143 | ) | | (10 | ) | | 1 |
| | (141 | ) |
Amounts reclassified from AOCI(b) | 1 |
| | — |
| | 181 |
| | — |
| | — |
| | 182 |
|
| Net current-period OCI | 12 |
|
| — |
|
| 38 |
|
| (10 | ) |
| 1 |
|
| 41 |
|
Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard(c) | — |
| | (10 | ) | | — |
| | — |
| | — |
| | (10 | ) |
| Ending balance | $ | (2 | ) |
| $ | — |
|
| $ | (2,960 | ) |
| $ | (33 | ) |
| $ | — |
|
| $ | (2,995 | ) |
Generation(a) |
|
|
|
|
|
|
|
|
| |
|
| Beginning balance | $ | (16 | ) | | $ | 3 |
| | $ | — |
| | $ | (23 | ) | | $ | (1 | ) | | $ | (37 | ) |
| OCI before reclassifications | 11 |
| | — |
| | — |
| | (10 | ) | | — |
| | 1 |
|
Amounts reclassified from AOCI(b) | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
| Net current-period OCI | 12 |
|
| — |
|
| — |
|
| (10 | ) |
| — |
|
| 2 |
|
Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard(c) | — |
| | (3 | ) | | — |
| | — |
| | — |
| | (3 | ) |
| Ending balance | $ | (4 | ) |
| $ | — |
|
| $ | — |
|
| $ | (33 | ) |
| $ | (1 | ) |
| $ | (38 | ) |
PECO(a) |
|
|
|
|
|
|
|
|
| |
|
| Beginning balance | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| OCI before reclassifications | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amounts reclassified from AOCI(b) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net current-period OCI | — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard(c) | — |
| | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) |
| Ending balance | $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2017 | Gains and
(Losses) on
Cash Flow
Hedges | | Unrealized
Gains on
Marketable
Securities | | Pension and
Non-Pension
Postretirement
Benefit Plan
items | | Foreign
Currency
Items | | AOCI of Investments
Unconsolidated
Affiliates | | Total |
Exelon(a) | | | | | | | | | | | |
| Beginning balance | $ | (17 | ) |
| $ | 4 |
|
| $ | (2,610 | ) |
| $ | (30 | ) |
| $ | (7 | ) | | $ | (2,660 | ) |
| OCI before reclassifications | (1 | ) |
| 6 |
|
| 11 |
|
| 7 |
|
| 6 |
| | 29 |
|
Amounts reclassified from AOCI(b) | 4 |
|
| — |
|
| 140 |
|
| — |
|
| — |
| | 144 |
|
| Net current-period OCI | 3 |
|
| 6 |
|
| 151 |
|
| 7 |
|
| 6 |
|
| 173 |
|
Impact of adoption of Reclassification of Certain Tax Effects from AOCI(d) | — |
| | — |
| | (539 | ) | | — |
| | — |
| | (539 | ) |
| Ending balance | $ | (14 | ) |
| $ | 10 |
|
| $ | (2,998 | ) |
| $ | (23 | ) |
| $ | (1 | ) |
| $ | (3,026 | ) |
Generation(a) |
|
|
|
|
|
|
|
|
| |
|
| Beginning balance | $ | (19 | ) |
| $ | 2 |
|
| $ | — |
|
| $ | (30 | ) |
| $ | (7 | ) | | $ | (54 | ) |
| OCI before reclassifications | (1 | ) |
| 1 |
|
| — |
|
| 7 |
|
| 6 |
| | 13 |
|
Amounts reclassified from AOCI(b) | 4 |
|
| — |
|
| — |
|
| — |
|
| — |
| | 4 |
|
| Net current-period OCI | 3 |
|
| 1 |
|
| — |
|
| 7 |
|
| 6 |
|
| 17 |
|
| Ending balance | $ | (16 | ) |
| $ | 3 |
|
| $ | — |
|
| $ | (23 | ) |
| $ | (1 | ) |
| $ | (37 | ) |
PECO(a) |
|
|
|
|
|
|
|
|
| |
|
| Beginning balance | $ | — |
|
| $ | 1 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
| | $ | 1 |
|
| OCI before reclassifications | — |
|
| — |
|
| — |
|
| — |
|
| — |
| | — |
|
Amounts reclassified from AOCI(b) | — |
|
| — |
|
| — |
|
| — |
|
| — |
| | — |
|
| Net current-period OCI | — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| Ending balance | $ | — |
|
| $ | 1 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 1 |
|
__________
| |
(a) | All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI. |
| |
(b) | See next tables for details about these reclassifications. |
| |
(c) | Exelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Financial Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million, $3 million and $1 million for Exelon, Generation and PECO, respectively. The amounts reclassified related to Rabbi Trusts. See Note 1 — Significant Accounting Policies for additional information.
|
| |
(d) | Exelon early adopted the new standard Reclassification of Certain Tax Effects from AOCI. The standard was adopted retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million, primarily related to deferred income taxes associated with Exelon’s pension and OPEB obligations. See Note 1 — Significant Accounting Policies for additional information.
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd, PECO, BGE, PHI, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the years ended December 31, 2018 and 2017. The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the years ended December 31, 2018 and 2017:
For the Year Ended December 31, 2018
|
| | | | | | | | | | |
| Details about AOCI components | | Items reclassified out of AOCI(a) | | Affected line item in the Statement of Operations and Comprehensive Income |
| | | Exelon | | Generation | | |
| Gains (Losses) on cash flow hedges | | | | | | |
| Other cash flow hedges | | $ | (1 | ) | | $ | (1 | ) | | Interest expense |
| | | (1 | ) |
| (1 | ) | | Total before tax |
| | | — |
| | — |
| | Tax benefit |
| | | $ | (1 | ) |
| $ | (1 | ) | | Net of tax |
| | | | | | | |
Amortization of pension and other postretirement benefit plan items |
Prior service costs(b) | | $ | 90 |
| | $ | — |
| | |
Actuarial losses(b) | | (333 | ) | | — |
| | |
| | | (243 | ) |
| — |
| | Total before tax |
| | | 62 |
| | — |
| | Tax benefit |
| | | $ | (181 | ) |
| $ | — |
| | Net of tax |
| | | | | | | |
| Total Reclassifications | | $ | (182 | ) |
| $ | (1 | ) | | Net of tax |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For the Year Ended December 31, 2017
|
| | | | | | | | | | |
| Details about AOCI components | | Items reclassified out of AOCI(a) | | Affected line item in the Statement of Operations and Comprehensive Income |
| | | Exelon | | Generation | | |
| Gains (Losses) on cash flow hedges | | | | | | |
| Other cash flow hedges | | $ | (5 | ) | | $ | (5 | ) | | Interest expense |
| | (5 | ) |
| (5 | ) |
| Total before tax |
| | 1 |
| | 1 |
| | Tax benefit |
| | $ | (4 | ) |
| $ | (4 | ) |
| Net of tax |
| | | | | | | |
| Amortization of pension and other postretirement benefit plan items | | | | | | |
Prior service costs(b) | | $ | 92 |
| | $ | — |
| | |
Actuarial losses(b) | | (324 | ) | | — |
| | |
| | | (232 | ) |
| — |
|
| Total before tax |
| | | 92 |
| | — |
| | Tax benefit |
| | | $ | (140 | ) |
| $ | — |
|
| Net of tax |
| | | | | | | |
| Total Reclassifications | | $ | (144 | ) |
| $ | (4 | ) |
| Net of tax |
__________
| |
(a) | Amounts in parenthesis represent a decrease in net income. |
| |
(b) | This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 16 — Retirement Benefits for additional information. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents income tax benefit (expense) allocated to each component of other comprehensive income (loss) during the years ended December 31, 2018, 2017 and 2016:
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Exelon | | | | | |
| Pension and non-pension postretirement benefit plans: | | | | | |
| Prior service benefit reclassified to periodic benefit cost | $ | 24 |
| | $ | 36 |
| | $ | 30 |
|
| Actuarial loss reclassified to periodic benefit cost | (86 | ) | | (128 | ) | | (118 | ) |
| Pension and non-pension postretirement benefit plans valuation adjustment | 50 |
| | 13 |
| | 115 |
|
| Change in unrealized gains on cash flow hedges | (5 | ) | | (7 | ) | | — |
|
| Change in unrealized gains (losses) on investments in unconsolidated affiliates | — |
| | (3 | ) | | 3 |
|
| Change in unrealized gains on marketable securities | — |
| | (1 | ) | | — |
|
| Total | $ | (17 | ) | | $ | (90 | ) |
| $ | 30 |
|
| | | | | | |
| Generation | | | | | |
| Change in unrealized gains on cash flow hedges | $ | (4 | ) | | $ | (6 | ) | | $ | (2 | ) |
| Change in unrealized gains (losses) on investments in unconsolidated affiliates | (1 | ) | | (3 | ) | | 3 |
|
| Change in unrealized gains on marketable securities | — |
| | (1 | ) | | — |
|
| Total | $ | (5 | ) | | $ | (10 | ) |
| $ | 1 |
|
22. Commitments and Contingencies (All Registrants)
Commitments
Constellation Merger Commitments (Exelon and Generation). In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion.
The direct investment included the construction of a new 21-story headquarters building in Baltimore for Generation’s competitive energy business that was substantially complete in November 2016 and is now occupied by approximately 1,500 Exelon employees. Generation's investment in leasehold improvements totaled approximately $90 million. In addition, Generation entered into a 20-year operating lease as the primary lessee of the building.
The direct investment commitment also included $450 million to $500 million relating to Exelon and Generation’s development or assistance in the development of 285 - 300 MWs of new generation in Maryland, which is expected to be completed within a period of 10 years after the merger. The MDPSC order contemplated various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damages payments. Exelon and Generation have incurred $458 million towards satisfying the commitment for new generation development in the state of Maryland, with approximately 220 MW of the new generation commencing with commercial operations to date and an additional 10 MW commitment satisfied through a liquidated damages payment made in the fourth quarter of 2016. Additionally, during the fourth quarter of 2016, given continued declines in projected energy and capacity prices, Generation terminated rights to certain development projects originally intended to meet its remaining 55 MW commitment amount. The commitment is expected to be satisfied via payment of liquidated damages or execution of a third party PPA, rather than by Generation constructing renewable generating assets. As a result, Exelon and Generation
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
recorded a pre-tax $50 million loss contingency in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016. The remaining commitment is to be paid on or before January 15, 2023 unless the period is extended by consent of Exelon and the State of Maryland. (a)As of December 31, 2018 and 2017, Exelon's and Generation's Consolidated Balance Sheets include a $502020, $13 million liability within Deferred credits and other liabilities for this remaining commitment.
Commercial Commitments (All Registrants). Exelon’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Expiration within |
| | Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
| Letters of credit | $ | 1,703 |
| | $ | 1,394 |
| | $ | 308 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | 1,402 |
| | 1,331 |
| | 33 |
| | 38 |
| | — |
| | — |
| | — |
|
| Financing trust guarantees | 378 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 378 |
|
Guaranteed lease residual values(b) | 24 |
| | 3 |
| | 3 |
| | 2 |
| | 3 |
| | 3 |
| | 10 |
|
| Total commercial commitments | $ | 3,507 |
| | $ | 2,728 |
| | $ | 344 |
| | $ | 41 |
| | $ | 3 |
| | $ | 3 |
| | $ | 388 |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
| |
(b) | Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $61 million, $19 million of which is a guarantee by Pepco, $26 million by DPL and $16 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote. |
Generation’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Expiration within |
| | Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
| Letters of credit | $ | 1,680 |
| | $ | 1,380 |
| | $ | 299 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a)
| 1,220 |
| | 1,201 |
| | 19 |
| | — |
| | — |
| | — |
| | — |
|
| Total commercial commitments | $ | 2,900 |
| | $ | 2,581 |
| | $ | 318 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
ComEd’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Expiration within |
| | Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
| Letters of credit | $ | 2 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | 12 |
| | 10 |
| | — |
| | 2 |
| | — |
| | — |
| | — |
|
| Financing trust guarantees | 200 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 200 |
|
| Total commercial commitments | $ | 214 |
| | $ | 12 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 200 |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PECO’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Expiration within |
| | Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
Surety bonds(a) | $ | 9 |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Financing trust guarantees | 178 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 178 |
|
| Total commercial commitments | $ | 187 |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 178 |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
BGE’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Expiration within |
| | Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
| Letters of credit | $ | 3 |
| | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | 17 |
| | 3 |
| | 14 |
| | — |
| | — |
| | — |
| | — |
|
| Total commercial commitments | $ | 20 |
| | $ | 5 |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
PHI commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Expiration within |
| | Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
| Letters of credit | $ | 8 |
| | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | $ | 41 |
| | $ | 41 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Guaranteed lease residual values(b) | 24 |
| | 3 |
| | 3 |
| | 2 |
| | 3 |
| | 3 |
| | 10 |
|
| Total commercial commitments | $ | 73 |
|
| $ | 44 |
|
| $ | 11 |
|
| $ | 2 |
|
| $ | 3 |
|
| $ | 3 |
|
| $ | 10 |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
| |
(b) | Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $61 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pepco commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Expiration within |
| | Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
| Letters of credit | $ | 8 |
| | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | $ | 33 |
| | $ | 33 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Guaranteed lease residual values(b) | 8 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 3 |
|
| Total commercial commitments | $ | 49 |
| | $ | 34 |
| | $ | 9 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 3 |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
| |
(b) | Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $19 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and Pepco believes the likelihood of payments being required under the guarantees is remote. |
DPL commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Expiration within |
| | Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
Surety bonds(a) | $ | 5 |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Guaranteed lease residual values(b) | 10 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 5 |
|
| Total commercial commitments | $ | 15 |
| | $ | 6 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 5 |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
| |
(b) | Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $26 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and DPL believes the likelihood of payments being required under the guarantees is remote. |
ACE commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Expiration within |
| | Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
Surety bonds(a) | $ | 3 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Guaranteed lease residual values(b) | 6 |
| | 1 |
| | 1 |
| | — |
| | 1 |
| | 1 |
| | 2 |
|
| Total commercial commitments | $ | 9 |
| | $ | 4 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | 2 |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
| |
(b) | Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $16 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and ACE believes the likelihood of payments being required under the guarantees is remote. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Leases (All Registrants)
Minimum future operating lease payments, including lease payments for contracted generation, vehicles, real estate, computers, rail cars, operating equipment and office equipment, as of December 31, 2018 were:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon(a)(b) | | Generation(a)(b) | | ComEd(a)(c) | | PECO(a)(c) | | BGE(a)(c)(d)(e) | | PHI(a) | | Pepco(a) | | DPL(a)(c) | | ACE(a) |
| 2019 | $ | 140 |
| | $ | 33 |
| | $ | 7 |
| | $ | 5 |
| | $ | 35 |
| | $ | 48 |
| | $ | 11 |
| | $ | 14 |
| | $ | 7 |
|
| 2020 | 149 |
| | 46 |
| | 5 |
| | 5 |
| | 35 |
| | 46 |
| | 10 |
| | 13 |
| | 6 |
|
| 2021 | 143 |
| | 46 |
| | 4 |
| | 5 |
| | 33 |
| | 43 |
| | 9 |
| | 12 |
| | 5 |
|
| 2022 | 126 |
| | 47 |
| | 4 |
| | 5 |
| | 18 |
| | 42 |
| | 8 |
| | 12 |
| | 5 |
|
| 2023 | 97 |
| | 46 |
| | 3 |
| | 5 |
| | 3 |
| | 39 |
| | 8 |
| | 10 |
| | 4 |
|
| Remaining years | 723 |
| | 545 |
| | — |
| | — |
| | 19 |
| | 159 |
| | 40 |
| | 35 |
| | 5 |
|
| Total minimum future lease payments | $ | 1,378 |
| | $ | 763 |
| | $ | 23 |
| | $ | 25 |
| | $ | 143 |
| | $ | 377 |
| | $ | 86 |
| | $ | 96 |
| | $ | 32 |
|
__________
| |
(a) | Includes amounts related to shared use land arrangements. |
| |
(b) | Excludes Generation’s contingent operating lease payments associated with contracted generation agreements. |
| |
(c) | Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years as such amounts would not be meaningful. ComEd's, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectively. Also includes amounts related to shared use land arrangements. |
| |
(d) | Includes all future lease payments on a 99-year real estate lease that expires in 2106. |
| |
(e) | The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022 , respectively. |
The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2018, 2017 and 2016:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, | Exelon | | Generation(a) | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
| 2018 | $ | 670 |
| | $ | 558 |
| | $ | 7 |
| | $ | 10 |
| | $ | 35 |
| | $ | 10 |
| | $ | 13 |
| | $ | 8 |
|
| 2017 | 709 |
| | 578 |
| | 9 |
| | 9 |
| | 32 |
| | 11 |
| | 16 |
| | 14 |
|
| 2016 | 777 |
| | 667 |
| | 15 |
| | 7 |
| | 22 |
| | 8 |
| | 15 |
| | 13 |
|
|
| | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the Year Ended December 31, 2018 | | For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| PHI | | | | | | | | |
| Rental expense under operating leases | $ | 48 |
| | $ | 63 |
| | $ | 49 |
| | | $ | 12 |
|
__________
| |
(a) | Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments table above. Payments made under Generation’s contracted generation lease agreements totaled $493 million, $508 million and $604 million during 2018, 2017 and 2016, respectively. Excludes contract amortization associated with purchase accounting and contract acquisitions. |
For information regarding capital lease obligations, see Note 13—Debt and Credit Agreements.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Nuclear Insurance (Exelon and Generation)
Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.
The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2018, the current liability limit per incident is $14.1 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.6 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer would be approximately $3.1 billion, however any amounts payable under this secondary layer would be capped at $454 million per year.
In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $14.1 billion limit for a single incident.
As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 2 — Variable Interest Entities for additional information on Generation’s operations relating to CENG.
Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.
NEIL may declare distributions to its members as a result of favorable operating experience. In recent years NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all. Generation's portion of the annual distribution declared by NEIL is estimated to be $58 million for 2018, and was $60 million and $21 million for 2017 and 2016, respectively. In addition, in March 2018, NEIL declared a supplemental distribution. Generation's portion of the supplemental distribution declared by NEIL was $31 million. The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $345 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.
NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
for all insured plants, the maximum recovery by Exelon will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.
For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial statements.
Spent Nuclear Fuel Obligation (Exelon and Generation)
Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation historically had paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. On November 19, 2013, the D.C. Circuit Court ordered the DOE to submit to Congress a proposal to reduce the current SNF disposal fee to zero, unless and until there is a viable disposal program. On May 9, 2014, the DOE notified Generation that the SNF disposal fee remained in effect through May 15, 2014, after which time the fee was set to zero. As a result, for the years ended December 31, 2018, 2017 and 2016, Generation did not incur any expense in SNF disposal fees. Until a new fee structure is in effect, Exelon and Generation will not accrue any furthertotal unrecognized compensation costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and itsnonvested performance has been, and isshares are expected to be delayed significantly.
The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding forrecognized over the creationremaining weighted-average period of the Yucca Mountain repository while the Obama Administration devised a new strategy for long-term SNF management. The Blue Ribbon Commission (BRC) on America’s Nuclear Future, appointed by the U.S. Energy Secretary, released a report on January 26, 2012, detailing comprehensive recommendations for creating a safe, long-term solution for managing and disposing of the nation’s SNF and high-level radioactive waste.1.8 years.
In early 2013, the DOE issued an updated “Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste” in response to the BRC recommendations. This strategy included a consolidated interim storage facility that was planned to be operational in 2025. However, due to continued delays on the part of the DOE, Generation currently assumes the DOE will begin accepting SNF in 2030 and uses that date for purposes of estimating the nuclear decommissioning asset retirement obligations. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage.
In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at Generation’s nuclear stations pending the DOE’s fulfillment of its obligations. Generation’s settlement agreement does not include FitzPatrick and FitzPatrick does not currently have a settlement agreement in place. Calvert Cliffs, Ginna and Nine Mile Point each have separate settlement agreements in place with the DOE which were extended during 2017 to provide for the reimbursement of SNF storage costs through December 31, 2019. Generation submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.
Under the settlement agreements, Generation has received cumulative cash reimbursements for costs incurred as follows:
|
| | | | | | | |
| | Total | | Net(a) |
Cumulative cash reimbursements(b)
| $ | 1,274 |
| | $ | 1,100 |
|
__________
| |
(a) | Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek. |
| |
(b) | Includes $53 and $49, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CENG. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2018 and 2017, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:
|
| | | | | | | |
| | December 31, 2018 |
| | December 31, 2017 |
|
DOE receivable - current(a) | $ | 124 |
| | $ | 94 |
|
DOE receivable - noncurrent(b) | 15 |
| | 15 |
|
Amounts owed to co-owners(a)(c) | (17 | ) | | (11 | ) |
__________
| |
(a) | Recorded in Accounts receivable, other. |
| |
(b) | Recorded in Deferred debits and other assets, other |
| |
(c) | Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities. |
The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon’s 2001 corporate restructuring. A prior owner of FitzPatrick also elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, Generation assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation. The amounts were recorded at fair value. See Note 4 - Mergers, Acquisitions and Dispositions for additional information on the FitzPatrick acquisition. As of December 31, 2018 and 2017, the SNF liability for the one-time fee with interest was $1,171 million and $1,147 million, respectively, which is included in Exelon's and Generation's Consolidated Balance Sheets. Interest for Exelon's and Generation's SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2018 was 2.351% for the deferred amount transferred from ComEd and 2.217% for the deferred FitzPatrick amount. The outstanding one-time fee obligations for the Nine Mile Point, Ginna, Oyster Creek and TMI units remain with the former owners. The Clinton and Calvert Cliffs units have no outstanding obligation. See Note 11 — Fair Value of Financial Assets and Liabilities for additional information.
Environmental Remediation Matters
General (All Registrants).The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies, or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
MGP Sites (Exelon and the Utility Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
•ComEd has identified 4221 sites 21 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 21 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2023. 2026.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
•PECO has identified 26has 8 sites 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements and 9 that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.2023.
•BGE has identified 134 sites 9 of which have been remediated and approved by the MDE and 4 that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2019.
2023.•DPL has identified 3 sites, 2 of which remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control. The remaining1 site that is currently under study and the required cost at the site is not expected to be material.
The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. See Note 4 — Regulatory Matters for additional information regarding the associated regulatory assets. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.
During the third quarter of 2018, the Utility Registrants completed a study of their future estimated environmental remediation requirements. The study resulted in a $48 million increase to the environmental liability and related regulatory asset for ComEd. The increase was primarily due to a revised closure strategy at one site, which resulted in an increase in the excavation area and depth of impacted soils from the site. The study did not result in a material change to the environmental liability for PECO, BGE, Pepco, DPL, and ACE.
As of December 31, 20182020 and 2017,2019, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Total environmental
investigation and
remediation liabilities | | Portion of total related to
MGP investigation and
remediation | | Total environmental
investigation and
remediation liabilities | | Portion of total related to
MGP investigation and
remediation |
| Exelon | $ | 483 | | | $ | 314 | | | $ | 478 | | | $ | 320 | |
| Generation | 121 | | | 0 | | | 105 | | | 0 | |
| ComEd | 293 | | | 293 | | | 304 | | | 303 | |
| PECO | 23 | | | 21 | | | 19 | | | 17 | |
| BGE | 2 | | | 0 | | | 2 | | | 0 | |
| PHI | 44 | | | 0 | | | 48 | | | 0 | |
| Pepco | 42 | | | 0 | | | 46 | | | 0 | |
| DPL | 1 | | | 0 | | | 1 | | | 0 | |
| ACE | 1 | | | 0 | | | 1 | | | 0 | |
|
| | | | | | | |
| December 31, 2018 | Total environmental investigation and remediation reserve | | Portion of total related to MGP investigation and remediation |
| Exelon | $ | 496 |
| | $ | 356 |
|
| Generation | 108 |
| | — |
|
| ComEd | 329 |
| | 327 |
|
| PECO | 27 |
| | 25 |
|
| BGE | 5 |
| | 4 |
|
| PHI | 27 |
| | — |
|
| Pepco | 25 |
| | — |
|
| DPL | 1 |
| | — |
|
| ACE | 1 |
| | — |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | |
| December 31, 2017 | Total environmental investigation and remediation reserve | | Portion of total related to MGP investigation and remediation |
| Exelon | $ | 466 |
| | $ | 315 |
|
| Generation | 117 |
| | — |
|
| ComEd | 285 |
| | 283 |
|
| PECO | 30 |
| | 28 |
|
| BGE | 5 |
| | 4 |
|
| PHI | 29 |
| | — |
|
| Pepco | 27 |
| | — |
|
| DPL | 1 |
| | — |
|
| ACE | 1 |
| | — |
|
Cotter Corporation (Exelon and Generation).The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the EPA issued a Record of Decision (ROD) approving a landfill cover remediation approach. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the supplemental feasibility study to the EPA for review. Since June 2012, the EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study. This further analysis was focused on a partial excavation remedial option. The PRPs provided the draft final Remedial Investigation and Feasibility Study (RI/FS) to the EPA in January 2018, which formed the basis for EPA’s proposed remedy selection, as further discussed below. ThereIncluding Cotter, there are currently three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.
OnIn September 27, 2018, the EPA issued its RODRecord of Decision (ROD) Amendment for the selection of thea final remedy for the West Lake Landfill Superfund site.remedy. The ROD modifiesAmendment modified the EPA’sremedy previously proposed plan forselected by EPA in its 2008 ROD. While the 2008 ROD
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
required only that the radiological materials and other wastes at the site be capped, the 2018 ROD Amendment requires partial excavation of the radiological materials by reducingin addition to the depths of the excavation.previously selected capping remedy. The ROD Amendment also allows for variation in depths of excavation depending on radiological concentrations. The EPA estimates thatand the ROD will result in a reduction of both radiological and non-radiological waste excavated, with corresponding reductions in the cost and schedule for the remedy. The next step is the negotiation ofPRPs have entered into a Consent Agreement byto perform the EPA with the PRPs to implement the ROD, a process thatRemedial Design, which is expected to be completed inby early 2022. In March 2019 the first quarterPRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Cotter (Generation’s indemnitee) provided a non-binding good faith offer to conduct, or finance, a portion of 2020.the remedy, subject to certain conditions. The total estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred collectively by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability, included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost for the entire remediation effort.cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required remediation remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Generation’sCotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial statements.
On January 16, 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater RI/FS and reimbursement of EPA’s oversight costs. The purposes of this new RI/FS are to define the nature and extent of any groundwater contamination from the West Lake Landfill site, determine the potential risk posed to human health and the environment, and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS for West Lake to be approximately $20 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
or the extent to which, if any, remediation activities will be required and cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future financial statements.
During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent and dangerous conditions at the landfill. The first involved installation by the PRPs of a non-combustible surface cover to protect against surface fires in areas where radiological materials are believed to have been disposed which was completed in 2018. The second action involved EPA's public statement that it will require the PRPs to construct a barrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Generation believes that the requirement to build a barrier wall is remote in light of other technologies that have been employed by the adjacent landfill owner. Finally, oneOne of the other PRPs the landfill owner and operator of the adjacent landfill, has indicated that it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not possesshave sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial statements.
OnIn January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation (RI)/Feasibility Study (FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $30 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability, included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood that, or the extent to which any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future financial statements.
In August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s (now Generation's) indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. The DOJ has not yet formally advisedPursuant to a series of annual agreements since 2011, the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million from all PRPs. The DOJ and the PRPs agreed to tollhave tolled the statute of limitations until August 201931, 2021 so that settlement discussions couldcan proceed. On August 3, 2020, the DOJ advised Cotter and the other PRPs that it is seeking approximately $90 million from all the PRPs and has directed that the PRPs must submit a good faith joint proposed settlement offer. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above.
Commencing in February 2012, a number of lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, as well as Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer or other serious illness due to Cotter's negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs are asserting public liability claims under the Price-Anderson Act. Their state law claims for negligence, strict liability, emotional distress, and medical monitoring have been dismissed. In the event of a finding of liability against Cotter, it is probable that Generation would be financially responsible due to its indemnification responsibilities of Cotter described above. The court has dismissed a number of the lawsuits as untimely, which has been upheld on appeal. Cotter and the remaining plaintiffs have engaged in settlement discussions pursuant to court-ordered mediation. During the second quarter of 2018, Generation determined a loss was probable based on the advancement of settlement proceedings and recorded an immaterial liability.
Benning Road Site (Exelon, Generation, PHI, and Pepco).In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility, which was deactivated in June 2012 and plant structure demolition was completed in July 2015.2012. The remaining portion of the site consists of a Pepco
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a Remediation Investigation (RI)/ Feasibility Study (FS)RI/FS for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The Consent Decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
that are determined to be attributable to past activities at the Benning Road site. Pursuant to Exelon's March 23, 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation.
Since 2013, Pepco and Pepco Energy Services (now Generation)Generation, pursuant to Exelon's 2016 acquisition of PHI) have been performing RI work and have submitted multiple draft RI reports to the DOEE. Once the RI work is completed,In September 2019, Pepco and Generation will issueissued a draft “final” RI report for review and comment bywhich DOEE and the public.approved on February 3, 2020. Pepco and Generation will then proceed to develop anare developing a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the RI and FS, and approval by the DOEE, by May 6, 2019.
Upon DOEE’sSeptember 16, 2021. After completion and approval of the final RI and FS, Reports, Pepco and Generation will have satisfied their obligations under the Consent Decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions. After consideringfor public comment on the Proposed Plan, DOEE willand then issue a Record of DecisionROD identifying any further response actions determined to be necessary. PHI, Pepco, and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon, PHI, and Pepco).Contemporaneous with the Benning Road site RI/FS being performed by Pepco and Generation, DOEE and certain federal agenciesthe National Park Service have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-D.C.Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. In March 2016, DOEE released a draft of the river-wide RI Report for public review and comment. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a “Consultative Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning RI/FS. Pepco responded that it will participate in the Consultative Working Group, but its participation is not an acceptance of any financial responsibility beyond the work that will be performed at the Benning Road site described above. In April 2018, DOEE released a draft remedial investigationRI report for public review and comment. Pepco submitted written comments toon the draft RI and participated in a public hearing. Pepco continues outreach efforts as appropriate to the agencies, governmental officials, community organizations and other key stakeholders. In May 2018 the District of Columbia Council extended the deadline for completion of the Record of Decision from June 30, 2018 until December 31, 2019. An appropriate liability for Pepco’s share of investigation costs has been accrued and is included in the table above. Although
Pepco has determined that it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management’s best estimate of its share of those costs. On September 30, 2020, DOEE released its Interim ROD. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion. Pepco cannot estimate thehas concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss at this time and no liability has been accrued for those future costs. A draft Feasibility Study of potential remedies and their estimated costs is being prepared bybeyond the agencies and is expected to be releasedamounts recorded, which are included in 2019, at which time Pepco will likely be in a better position to estimate the range of loss.table above.
In addition to the activities associated with the remedial process outlined above, there is a complementary statutory program thatCERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to determine if any natural resources have been damagedwithin their jurisdiction as a result of the contamination that is being remediated, and, if so, that a plan be developed by the federal, state and localremediated. The Trustees can seek compensation from responsible parties for those resources to restore them to their condition before injury from the environmental contaminants. If natural resources are not restored, then compensation for the injury can be sought from the party responsible for the release of the contaminants. The assessment of Natural Resource Damages (NRD) typically takes place following cleanup because cleanups sometimes also effectively restore habitat.such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of thisa Natural Resources Damages (NRD) assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, itPepco cannot reasonably estimate the range of loss.
Litigation and Regulatory Matters
Asbestos Personal Injury Claims (Exelon Generation, ComEd and PECO)Generation). Generation maintains estimated liabilitiesa reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
At December 31, 20182020 and 2017,2019, Exelon and Generation had recorded estimated liabilities of approximately $79$89 million and $78$83 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2018,2020, approximately $24$25 million of this amount related to 238261 open claims presented to Generation, while the remaining $55$64 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050,2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.
ThereIt is a reasonable possibilityreasonably possible that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued and the increases could have a material, unfavorable impact on Exelon'sExelon’s and Generation’s financial statements. However, management cannot reasonably estimate a range of loss beyond the amounts recorded.
Fund Transfer Restrictions (All Registrants). Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.
Under applicable law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to Exelon.
ComEd has agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.
Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the DPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid itif its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.
Conduit Lease with City of Baltimore (Exelon and BGE). On September 23, 2015, the Baltimore City Board of Estimates approved an increase in annual rental fees for access to the Baltimore City underground conduit system
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
effective November 1, 2015, from $12 million to $42 million, subject to an annual increase thereafter based on the Consumer Price Index. BGE subsequently entered into litigation with the City regarding the amount of and basis for establishing the conduit fee. On November 30, 2016, the Baltimore City Board of Estimates approved a settlement agreement entered into between BGE and the City to resolve the disputes and pending litigation related to BGE's use of and payment for the underground conduit system. As a result of the settlement, the parties entered into a six-year lease that reduces the annual expense to $25 million in the first three years and caps the annual expense in the last three years to not more than $29 million. BGE recorded a decrease to Operating and maintenance expense in the fourth quarter of 2016 of approximately $28 million for the reversal of the previously higher fees accrued as well as the settlement of prior year disputed fee true-up amounts.
City of Everett Tax Increment Financing Agreement (Exelon and Generation).On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 &and 9 on the grounds that the total investment in Mystic Units 8 &and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. Generation vigorously contested the City’s claims before the EACC and will continue to do so inOn January 8, 2020, the Massachusetts Superior Court proceeding. Generation continuesaffirmed the decision of the EACC denying the City's petition. The City had until March 9, 2020 to believe thatappeal the City’s claim lacks merit. Accordingly, Generation has not recordeddecision and did not. As a liability for payment resulting from such a revocation, nor can Generation estimate a reasonably possible range of loss, if any, associated with any such revocation. Further, itresult, the decision is final and the case is resolved. It is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 2019,on June 30, 2020, could be material to Generation’s financial statements.
Deferred Prosecution Agreement (DPA) and Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the U.S. Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date. The payments were recorded within Operating and maintenance expense in Exelon’s and ComEd’s Consolidated Statements of Operations and Comprehensive Income in the second quarter of 2020. The payments will not be recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. Exelon made equity contributions to ComEd of $200 million in 2020. On August 13, 2020, a motion was filed in the U.S. District Court for the Northern District of Illinois by a ComEd customer and on behalf of ComEd customers seeking to enjoin ComEd from paying these funds to the U.S. Treasury and requiring the U.S. government to establish a victims’ restitution fund from which the $200 million would be disbursed to ComEd customers. The motion was denied without prejudice on November 6, 2020 and ComEd submitted the $200 million payment to the U.S. Treasury. On January 6, 2021, the customer petitioned the Seventh Circuit for a writ of mandamus to seek review of the district court’s ruling, but on January 8, 2021, the Seventh Circuit denied the petition. On January 22, 2021, the customer petitioned the Seventh Circuit for rehearing of its denial of his petition for a writ of mandamus. On February 5, 2021, the Seventh Circuit denied the petition for rehearing.
Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon.
The SEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the SEC. Exelon and ComEd cannot predict the outcome of the SEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with respect to the SEC investigation, as this contingency is neither probable nor reasonably estimable at this time.
Subsequent to Exelon announcing the receipt of the subpoenas, various lawsuits have been filed and various demand letters have been received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:
•A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. Briefing was completed on February 17, 2021.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
•A derivative shareholder lawsuit was filed against Exelon, its directors and certain officers of Exelon and ComEd in April 2020 alleging, among other things, breaches of fiduciary duties also purporting to relate to matters that are the subject of the subpoenas and the SEC investigation. The plaintiff voluntarily dismissed this derivative action without prejudice to refile on July 28, 2020.
•Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. These three state cases were consolidated into a single action in October of 2020. In addition, on November 2, 2020, the Citizens Utility Board (CUB) filed a motion to intervene in the state cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November 23, 2020, the court allowed CUB’s intervention, but denied CUB’s request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion is ongoing.
•Four putative class action lawsuits against ComEd and Exelon were filed in federal court in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, CUB filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. In addition, on December 2, 2020, the court appointed interim lead plaintiffs in the federal cases which consisted of counsel for three of the four federal cases. These plaintiffs filed a consolidated complaint on January 5, 2021. CUB also filed its own complaint against ComEd only on the same day. The remaining federal case, Potter, et al. v. Exelon et al, differed from the other lawsuits as it named additional individual defendants not named in the consolidated complaint. On January 10, 2021, the Potter plaintiffs filed a motion asking the court to clarify that their class action complaint against ComEd, Exelon and the individual named defendants remains in effect, notwithstanding the consolidated amended complaint, and asked the court to stay the Potter case. On January 21, 2021, the court determined that the appointed lead counsel had sole discretion to determine which parties to name as plaintiffs and defendants, and that the Potter plaintiffs have the option to opt-out of that class and file a separate, individual action against the defendants named in their original complaint. The Potter plaintiffs have until March 23, 2021 to make that decision.
•Four shareholders sent letters to the Exelon Board of Directors in 2020 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA.
No loss contingencies have been reflected in Exelon’s and ComEd’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.
General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility,reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
20. Shareholders' Equity (Exelon and Utility Registrants)
ComEd Common Stock Warrants
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 20 — Shareholders' Equity
The following table presents warrants outstanding to purchase ComEd common stock and shares of common stock reserved for the conversion of warrants. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants.
| | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 |
| Warrants outstanding | 60,143 | | | 60,228 | |
| Common Stock reserved for conversion | 20,048 | | | 20,076 | |
Share Repurchases
There currently is 0 Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management.
Preferred and Preference Securities
The following table presents Exelon, ComEd, PECO, BGE, Pepco, and ACE's shares of preferred securities authorized, NaN of which were outstanding as of December 31, 2020 and 2019. There are 0 shares of preferred securities authorized for DPL.
| | | | | |
| Preferred Securities Authorized |
| Exelon | 100,000,000 | |
| ComEd | 850,000 | |
| PECO | 15,000,000 | |
| BGE | 1,000,000 | |
| Pepco | 6,000,000 | |
ACE(a) | 2,799,979 | |
__________
(a)Includes 799,979 shares of cumulative preferred stock and 2,000,000 of no-par preferred stock as of December 31, 2020 and 2019.
The following table presents ComEd's, BGE's, and ACE's preference securities authorized, NaN of which were outstanding as of December 31, 2020 and 2019. There are 0 shares of preference securities authorized for Exelon, PECO, Pepco, and DPL.
| | | | | |
| Preference Securities Authorized |
| ComEd | 6,810,451 | |
BGE(a) | 6,500,000 | |
| ACE | 3,000,000 | |
__________
(a)Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2020 and 2019.
21. Stock-Based Compensation Plans (All Registrants)
Stock-Based Compensation Plans
Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards, restricted stock units, and stock options. At December 31, 2020, there were approximately 34 million shares authorized for issuance under the LTIP. For the years ended December 31, 2020, 2019, and 2018, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.
The Registrants grant cash awards. The following table does not include expense related to these plans as they are not considered stock-based compensation plans under the applicable authoritative guidance.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 21 — Stock-Based Compensation Plans
The following table presents the stock-based compensation expense included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The Utility Registrants' stock-based compensation expense for the years ended December 31, 2020, 2019, and 2018 was not material.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| Exelon | 2020 | | 2019 | | 2018 |
| Total stock-based compensation expense included in operating and maintenance expense | $ | 64 | | | $ | 77 | | | $ | 208 | |
| Income tax benefit | (16) | | | (20) | | | (54) | |
| Total after-tax stock-based compensation expense | $ | 48 | | | $ | 57 | | | $ | 154 | |
| Generation | | | | | |
| Total stock-based compensation expense included in operating and maintenance expense | $ | 27 | | | $ | 37 | | | $ | 77 | |
| Income tax benefit | (7) | | | (10) | | | (20) | |
| Total after-tax stock-based compensation expense | $ | 20 | | | $ | 27 | | | $ | 57 | |
Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The following table presents information regarding Exelon’s realized tax benefit when distributed:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| Performance share awards | $ | 21 | | | $ | 41 | | | $ | 16 | |
| Restricted stock units | 15 | | | 24 | | | 28 | |
Performance Share Awards
Performance share awards are granted under the LTIP. The performance share awards are settled 50% in common stock and 50% in cash at the end of the three-year performance period, except for awards granted to vice presidents and higher officers that are settled 100% in cash if certain ownership requirements are satisfied.
The common stock portion of the performance share awards is considered an equity award and is valued based on Exelon's stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established.
For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant.
Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
The following table summarizes Exelon’s nonvested performance share awards activity:
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 21 — Stock-Based Compensation Plans
| | | | | | | | | | | |
| Shares | | Weighted Average
Grant Date Fair
Value (per share) |
Nonvested at December 31, 2019(a) | 1,709,755 | | | $ | 39.21 | |
| Granted | 1,122,378 | | | 46.61 | |
| Change in performance | (751,309) | | | 42.51 | |
| Vested | (747,551) | | | 35.70 | |
| Forfeited | (67,964) | | | 45.59 | |
Undistributed vested awards(b) | (334,917) | | | 50.76 | |
Nonvested at December 31, 2020(a) | 930,392 | | | $ | 43.67 | |
__________
(a)Excludes 1,414,661 and 2,017,870 of performance share awards issued to retirement-eligible employees as of December 31, 2020 and 2019, respectively, as they are fully vested.
(b)Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2020.
The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020(a) | | 2019 | | 2018 |
| Weighted average grant date fair value (per share) | $ | 46.61 | | | $ | 47.37 | | | $ | 38.15 | |
| Total fair value of performance shares vested | 39 | | | 158 | | | 61 | |
| Total fair value of performance shares settled in cash | 63 | | | 131 | | | 49 | |
__________
(a)As of December 31, 2020, $13 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.8 years.
Restricted Stock Units
Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.
The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized ratably over the first six months in the year of grant if the employee reaches retirement eligibility prior to July 1st of the grant year or through the date of which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
The following table summarizes Exelon’s nonvested restricted stock unit activity:
| | | | | | | | | | | |
| Shares | | Weighted Average
Grant Date Fair
Value (per share) |
Nonvested at December 31, 2019(a) | 1,498,713 | | | $ | 40.35 | |
| Granted | 847,382 | | | 46.33 | |
| Vested | (725,151) | | | 38.38 | |
| Forfeited | (52,046) | | | 45.20 | |
Undistributed vested awards(b) | (454,768) | | | 45.91 | |
Nonvested at December 31, 2020(a) | 1,114,130 | | $ | 43.67 | |
__________
(a)Excludes 748,165 and 863,196 of restricted stock units issued to retirement-eligible employees as of December 31, 2020 and 2019, respectively, as they are fully vested.
(b)Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2020.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 21 — Stock-Based Compensation Plans
The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020(a) | | 2019 | | 2018 |
| Weighted average grant date fair value (per share) | $ | 46.33 | | | $ | 45.65 | | | $ | 38.60 | |
| Total fair value of restricted stock units vested | 54 | | | 92 | | | 106 | |
__________
(a)As of December 31, 2020, $23 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.3 years.
Stock Options
Non-qualified stock options to purchase shares of Exelon’s common stock were granted through 2012 under the LTIP. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Stock options will expire no later than ten years from the date of grant.
At December 31, 2020 all stock options were vested and there were no unrecognized compensation costs.
The following table presents information with respect to stock option activity:
| | | | | | | | | | | | | | | | | | | | | | | |
| Shares | | Weighted
Average
Exercise
Price
(per share) | | Weighted
Average
Remaining
Contractual
Life
(years) | | Aggregate
Intrinsic
Value |
| Balance of shares outstanding at December 31, 2019 | 1,889,045 | | | $ | 40.43 | | | 1.56 | | $ | 10 | |
| Options exercised | (475,827) | | | 38.30 | | | | | 5 | |
| | | | | | | |
| Options expired | (147,808) | | | 46.07 | | | | | |
| Balance of shares outstanding at December 31, 2020 | 1,265,410 | | | $ | 40.57 | | | 0.91 | | $ | 3 | |
Exercisable at December 31, 2020(a) | 1,265,410 | | | $ | 40.57 | | | 0.91 | | $ | 3 | |
__________
(a)Includes stock options issued to retirement eligible employees.
The following table summarizes additional information regarding stock options exercised:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
Intrinsic value(a) | $ | 5 | | | $ | 9 | | | $ | 12 | |
| Cash received for exercise price | 18 | | | 59 | | | 56 | |
__________
(a)The difference between the market value on the date of exercise and the option exercise price.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 22 — Changes in Accumulated Other Comprehensive Income
22. Changes in Accumulated Other Comprehensive Income (Exelon)
The following tables present changes in Exelon's AOCI, net of tax, by component:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gains and
(Losses) on
Cash Flow
Hedges | | Unrealized
Gains and (Losses) on
Marketable
Securities | | Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a) | | Foreign
Currency
Items | | AOCI of Investments
Unconsolidated
Affiliates (b) | | Total |
| Balance at December 31, 2017 | $ | (14) | | | $ | 10 | | | $ | (2,998) | |
| $ | (23) | | | $ | (1) | | | $ | (3,026) | |
| OCI before reclassifications | 11 | | | 0 | | | (143) | | | (10) | | | 1 | | | (141) | |
| Amounts reclassified from AOCI | 1 | | | 0 | | | 181 | | | 0 | | | 0 | | | 182 | |
| Net current-period OCI | 12 | | | 0 | | | 38 | | | (10) | | | 1 | | | 41 | |
Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard(c) | 0 | | | (10) | | | 0 | | | 0 | | | 0 | | | (10) | |
| Balance at December 31, 2018 | $ | (2) | | | $ | 0 | | | $ | (2,960) | | | $ | (33) | | | $ | 0 | | | $ | (2,995) | |
| OCI before reclassifications | 0 | | | 0 | | | (289) | | | 6 | | | (2) | | | (285) | |
| Amounts reclassified from AOCI | 0 | | | 0 | | | 84 | | | 0 | | | 2 | | | 86 | |
| Net current-period OCI | 0 | | | 0 | | | (205) | | | 6 | | | 0 | | | (199) | |
| Balance at December 31, 2019 | $ | (2) | | | $ | 0 | | | $ | (3,165) | | | $ | (27) | | | $ | 0 | | | $ | (3,194) | |
| OCI before reclassifications | (3) | | | 0 | | | (357) | | | 4 | | | 0 | | | (356) | |
| Amounts reclassified from AOCI | 0 | | | 0 | | | 150 | | | 0 | | | 0 | | | 150 | |
| Net current-period OCI | (3) | | | 0 | | | (207) | | | 4 | | | 0 | | | (206) | |
| Balance at December 31, 2020 | $ | (5) | | | $ | 0 | | | $ | (3,372) | | | $ | (23) | | | $ | 0 | | | $ | (3,400) | |
__________
(a)This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 15 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
(b)All amounts are net of noncontrolling interests.
(c)Exelon adopted the new standard Recognition and Measurement of Financial Assets and Financial Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million for Exelon. The amounts reclassified related to Rabbi Trusts.
The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):
| | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Pension and non-pension postretirement benefit plans: | | | | | |
| Prior service benefit reclassified to periodic benefit cost | $ | 16 | | | $ | 23 | | | $ | 24 | |
| Actuarial loss reclassified to periodic benefit cost | (66) | | | (52) | | | (86) | |
| Pension and non-pension postretirement benefit plans valuation adjustment | 122 | | | 100 | | | 50 | |
23. Variable Interest Entities (Exelon, Generation, PHI, and ACE)
At December 31, 2020 and 2019, Exelon, Generation, PHI, and ACE collectively consolidated several VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — Variable Interest Entities
Consolidated VIEs
The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements of Exelon, Generation, PHI, and ACE as of December 31, 2020 and 2019. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to the general credit of Exelon, Generation, PHI, and ACE.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Exelon | | Generation | | PHI(a) | | ACE | | Exelon | | Generation | | PHI(a) | | ACE |
| Cash and cash equivalents | $ | 98 | | | $ | 98 | | | $ | 0 | | | $ | 0 | | | $ | 163 | | | $ | 163 | | | $ | 0 | | | $ | 0 | |
| Restricted cash and cash equivalents | 47 | | | 44 | | | 3 | | | 3 | | | 88 | | | 85 | | | 3 | | | 3 | |
| Accounts receivable | | | | | | | | | | | | | | | |
| Customer | 148 | | | 148 | | | 0 | | | 0 | | | 151 | | | 151 | | | 0 | | | 0 | |
| Other | 36 | | | 36 | | | 0 | | | 0 | | | 39 | | | 39 | | | 0 | | | 0 | |
| Unamortized energy contract assets | 22 | | | 22 | | | 0 | | | 0 | | | 23 | | | 23 | | | 0 | | | 0 | |
| Inventories, net | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Materials and supplies | 244 | | | 244 | | | 0 | | | 0 | | | 227 | | | 227 | | | 0 | | | 0 | |
Assets held for sale(b) | 101 | | | 101 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Other current assets | 674 | | | 669 | | | 5 | | | 0 | | | 32 | | | 31 | | | 1 | | | 0 | |
| Total current assets | 1,370 | | | 1,362 | | | 8 | | | 3 | | | 723 | | | 719 | | | 4 | | | 3 | |
| | | | | | | | | | | | | | | |
| Property, plant and equipment, net | 5,803 | | | 5,803 | | | 0 | | | 0 | | | 6,022 | | | 6,022 | | | 0 | | | 0 | |
| Nuclear decommissioning trust funds | 3,007 | | | 3,007 | | | 0 | | | 0 | | | 2,741 | | | 2,741 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | |
| Unamortized energy contract assets | 249 | | | 249 | | | 0 | | | 0 | | | 250 | | | 250 | | | 0 | | | 0 | |
| Other noncurrent assets | 52 | | | 42 | | | 10 | | | 10 | | | 89 | | | 73 | | | 16 | | | 14 | |
| Total noncurrent assets | 9,111 | | | 9,101 | | | 10 | | | 10 | | | 9,102 | | | 9,086 | | | 16 | | | 14 | |
Total assets(c) | $ | 10,481 | | | $ | 10,463 | | | $ | 18 | | | $ | 13 | | | $ | 9,825 | | | $ | 9,805 | | | $ | 20 | | | $ | 17 | |
| | | | | | | | | | | | | | | |
| Long-term debt due within one year | $ | 94 | | | $ | 68 | | | $ | 26 | | | $ | 21 | | | $ | 544 | | | $ | 523 | | | $ | 21 | | | $ | 20 | |
| Accounts payable | 81 | | | 81 | | | 0 | | | 0 | | | 106 | | | 106 | | | 0 | | | 0 | |
| Accrued expenses | 70 | | | 70 | | | 0 | | | 0 | | | 70 | | | 70 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | |
| Unamortized energy contract liabilities | 4 | | | 4 | | | 0 | | | 0 | | | 8 | | | 8 | | | 0 | | | 0 | |
Liabilities held for sale(b) | 16 | | | 16 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Other current liabilities | 5 | | | 5 | | | 0 | | | 0 | | | 3 | | | 3 | | | 0 | | | 0 | |
| Total current liabilities | 270 | | | 244 | | | 26 | | | 21 | | | 731 | | | 710 | | | 21 | | | 20 | |
| | | | | | | | | | | | | | | |
| Long-term debt | 889 | | | 889 | | | 0 | | | 0 | | | 527 | | | 504 | | | 23 | | | 21 | |
| | | | | | | | | | | | | | | |
| Asset retirement obligations | 2,318 | | | 2,318 | | | 0 | | | 0 | | | 2,128 | | | 2,128 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Unamortized energy contract liabilities | 0 | | | 0 | | | 0 | | | 0 | | | 1 | | | 1 | | | 0 | | | 0 | |
| Other noncurrent liabilities | 129 | | | 129 | | | 0 | | | 0 | | | 89 | | | 89 | | | 0 | | | 0 | |
| Total noncurrent liabilities | 3,336 | | | 3,336 | | | 0 | | | 0 | | | 2,745 | | | 2,722 | | | 23 | | | 21 | |
Total liabilities(d) | $ | 3,606 | | | $ | 3,580 | | | $ | 26 | | | $ | 21 | | | $ | 3,476 | | | $ | 3,432 | | | $ | 44 | | | $ | 41 | |
__________
(a)Includes certain purchase accounting adjustments from the PHI merger not pushed down to ACE.
(b)Generation entered into an agreement for the sale of a significant portion of Generation's solar business. As a result of this transaction, in the fourth quarter of 2020, Exelon and Generation reclassified the consolidated VIEs' solar assets and
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — Variable Interest Entities
liabilities as held for sale. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the sale of the solar business.
(c)Exelon's and Generation's balances include unrestricted assets for current unamortized energy contract assets of $22 million and $23 million, Property, plant, and equipment of $1 million and $20 million, non-current unamortized energy contract assets of $249 million and $250 million, and Assets held for sale of $9 million and $0 million as of December 31, 2020 and 2019, respectively.
(d)Exelon's and Generation's balances include liabilities with recourse of $8 million and $3 million as of December 31, 2020 and 2019, respectively.
As of December 31, 2020 and 2019, Exelon's and Generation's consolidated VIEs consist of:
| | | | | | | | |
| Consolidated VIE or VIE groups: | Reason entity is a VIE: | Reason Generation is primary beneficiary: |
| CENG - A joint venture between Generation and EDF. Generation has a 50.01% equity ownership in CENG. See additional discussion below. | Disproportionate relationship between equity interest and operational control as a result of the NOSA described further below. | Generation conducts the operational activities. |
| EGRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP. See additional discussion below. | Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. | Generation conducts the operational activities. |
| Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by EGRP. Generation is a minority interest holder. | Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. | Generation conducts the operational activities. |
| Antelope Valley - A solar generating facility, which is 100% owned by Generation. Antelope Valley sells all of its output to PG&E through a PPA. | The PPA contract absorbs variability through a performance guarantee. | Generation conducts all activities. |
Equity investment in distributed energy company - Generation has a 31% equity ownership. This distributed energy company has an interest in an unconsolidated VIE. (See Unconsolidated VIEs disclosure below).
Generation fully impaired this investment in the third quarter of 2019. Refer to Note 12 — Asset Impairments for additional information. | Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. | Generation conducts the operational activities. |
NER - A bankruptcy remote, special purpose entity which is 100% owned by Generation, which purchases certain of Generation’s customer accounts receivable arising from the sale of retail electricity.
NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 6 —Accounts Receivablefor additional information on the sale of receivables. | Equity capitalization is insufficient to support its operations. | Generation conducts all activities. |
CENG - On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the NOSA pursuant to which Generation conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF.
EDF has the option to sell its 49.99% equity interest in CENG to Generation. On November 20, 2019, Generation received notice of EDF's intention to exercise the put option to sell its interest in CENG to Generation and the put automatically exercised on January 19, 2020. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information.
Exelon and Generation, where indicated, provide the following support to CENG:
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — Variable Interest Entities
•Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. See Note 19 — Commitments and Contingencies for more details,
•Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and
•Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.
EGRP - EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by EGRP. Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. There is limited recourse to Generation related to certain solar and wind entities.
In 2017, Generation’s interests in EGRP were contributed to and are pledged for the EGR IV non-recourse debt project financing structure. Refer to Note 17 — Debt and Credit Agreements for additional information.
As of December 31, 2020 and 2019, Exelon's, PHI's and ACE's consolidated VIE consists of:
| | | | | | | | |
| Consolidated VIEs: | Reason entity is a VIE: | Reason ACE is the primary beneficiary: |
| ACE Funding - A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. Proceeds from the sale of each series of Transition Bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on Transition Bonds and related taxes, expenses, and fees. | ACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ATF. The bondholders also have a variable interest for the investment made to purchase the Transition Bonds. | ACE controls the servicing activities. |
Unconsolidated VIEs
Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements.
As of December 31, 2020 and 2019, Exelon and Generation had significant unconsolidated variable interests in several VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements.
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — Variable Interest Entities
The following table presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Commercial Agreement VIEs | | Equity Investment VIEs | | Total | | Commercial
Agreement
VIEs | | Equity
Investment
VIEs | | Total |
Total assets(a) | $ | 777 | | | $ | 401 | | | $ | 1,178 | | | $ | 636 | | | $ | 443 | | | $ | 1,079 | |
Total liabilities(a) | 61 | | | 223 | | | 284 | | | 33 | | | 227 | | | 260 | |
Exelon's ownership interest in VIE(a) | 0 | | | 157 | | | 157 | | | 0 | | | 191 | | | 191 | |
Other ownership interests in VIE(a) | 716 | | | 21 | | | 737 | | | 604 | | | 25 | | | 629 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
__________
(a)These items represent amounts on the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. Exelon and Generation do not have any exposure to loss as they do not have a carrying amount in the equity investment VIEs as of December 31, 2020 and 2019.
As of December 31, 2020 and 2019, Exelon's and Generation's unconsolidated VIEs consist of:
| | | | | | | | |
| Unconsolidated VIE groups: | Reason entity is a VIE: | Reason Generation is not the primary beneficiary: |
Equity investments in distributed energy companies -
1) Generation has a 90% equity ownership in a distributed energy company. 2) Generation, via a consolidated VIE, has a 90% equity ownership in another distributed energy company (See Consolidated VIEs disclosure above).
Generation fully impaired this investment in the third quarter of 2019. Refer to Note 12 — Asset Impairments for additional information. | Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. | Generation does not conduct the operational activities. |
| Energy Purchase and Sale agreements - Generation has several energy purchase and sale agreements with generating facilities. | PPA contracts that absorb variability through fixed pricing. | Generation does not conduct the operational activities. |
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
24. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Taxes other than income taxes |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | |
Utility(a) | $ | 859 | | | $ | 99 | | | $ | 238 | | | $ | 135 | | | $ | 87 | | | $ | 299 | | | $ | 275 | | | $ | 21 | | | $ | 3 | |
| Property | 602 | | | 265 | | | 30 | | | 16 | | | 164 | | | 126 | | | 84 | | | 39 | | | 3 | |
| Payroll | 235 | | | 113 | | | 27 | | | 16 | | | 17 | | | 25 | | | 7 | | | 5 | | | 3 | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | |
Utility(a) | $ | 881 | | | $ | 112 | | | $ | 242 | | | $ | 132 | | | $ | 90 | | | $ | 304 | | | $ | 286 | | | $ | 18 | | | $ | 0 | |
| Property | 595 | | | 274 | | | 29 | | | 17 | | | 153 | | | 122 | | | 85 | | | 34 | | | 2 | |
| Payroll | 232 | | | 115 | | | 27 | | | 15 | | | 17 | | | 24 | | | 7 | | | 4 | | | 2 | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2018 | | | | | | | | | | | | | | | | | |
Utility(a) | $ | 919 | | | $ | 114 | | | $ | 243 | | | $ | 131 | | | $ | 94 | | | $ | 337 | | | $ | 316 | | | $ | 21 | | | $ | 0 | |
| Property | 557 | | | 273 | | | 30 | | | 15 | | | 143 | | | 94 | | | 58 | | | 32 | | | 3 | |
| Payroll | 247 | | | 130 | | | 27 | | | 16 | | | 17 | | | 24 | | | 5 | | | 3 | | | 2 | |
__________
(a)Generation’s utility tax represents gross receipts tax related to its retail operations, and the Utility Registrants’ utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2018, 2017 and 2016.Income.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the year ended December 31, 2018 |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Taxes other than income | | | | | | | | | | | | | | | | | |
Utility(a) | $ | 919 |
| | $ | 114 |
| | $ | 243 |
| | $ | 131 |
| | $ | 94 |
| | $ | 337 |
| | $ | 316 |
| | $ | 21 |
| | $ | — |
|
| Property | 557 |
| | 273 |
| | 30 |
| | 15 |
| | 143 |
| | 94 |
| | 58 |
| | 32 |
| | 3 |
|
| Payroll | 247 |
| | 130 |
| | 27 |
| | 16 |
| | 17 |
| | 24 |
| | 5 |
| | 3 |
| | 2 |
|
| Other | 60 |
| | 39 |
| | 11 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total taxes other than income | $ | 1,783 |
| | $ | 556 |
| | $ | 311 |
| | $ | 163 |
| | $ | 254 |
|
| $ | 455 |
| | $ | 379 |
|
| $ | 56 |
|
| $ | 5 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other, Net |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: |
Net realized income on NDT funds(a) |
| Regulatory Agreement Units | $ | 185 | | | $ | 185 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Non-regulatory Agreement Units | 160 | | | 160 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory Agreement Units | 724 | | | 724 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Non-regulatory Agreement Units | 391 | | | 391 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Regulatory offset to NDT fund-related activities(b) | (729) | | | (729) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Decommissioning-related activities | 731 | | | 731 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| AFUDC—Equity | 104 | | | 0 | | | 29 | | | 17 | | | 22 | | | 36 | | | 28 | | | 4 | | | 4 | |
| Non-service net periodic benefit cost | 53 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Unrealized gains from equity investments(c) | 186 | | | 186 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: |
Net realized income on NDT funds(a) |
| Regulatory Agreement Units | $ | 297 | | | $ | 297 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Non-regulatory Agreement Units | 363 | | | 363 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory Agreement Units | 795 | | | 795 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Non-regulatory Agreement Units | 411 | | | 411 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Regulatory offset to NDT fund-related activities(b) | (876) | | | (876) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Decommissioning-related activities | 990 | | | 990 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| AFUDC—Equity | 85 | | | 0 | | | 17 | | | 13 | | | 21 | | | 34 | | | 25 | | | 4 | | | 5 | |
| Non-service net periodic benefit cost | 13 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2018 | | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: |
Net realized income on NDT funds(a) |
| Regulatory Agreement Units | $ | 506 | | | $ | 506 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Non-regulatory Agreement Units | 302 | | | 302 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Net unrealized losses on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory Agreement Units | (715) | | | (715) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Non-regulatory Agreement Units | (483) | | | (483) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Regulatory offset to NDT fund-related activities(b) | 171 | | | 171 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Decommissioning-related activities | (219) | | | (219) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| AFUDC—Equity | 69 | | | 0 | | | 19 | | | 7 | | | 18 | | | 25 | | | 22 | | | 2 | | | 1 | |
| Non-service net periodic benefit cost | (47) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
__________
(a)Realized income includes interest, dividends, and realized gains and losses on sales of NDT fund investments.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the year ended December 31, 2017 |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Taxes other than income | | | | | | | | | | | | | | | | | |
Utility(a) | $ | 898 |
| | $ | 126 |
| | $ | 240 |
| | $ | 125 |
| | $ | 89 |
| | $ | 318 |
| | $ | 300 |
| | $ | 18 |
| | $ | — |
|
| Property | 545 |
| | 269 |
| | 28 |
| | 14 |
| | 132 |
| | 101 |
| | 62 |
| | 32 |
| | 3 |
|
| Payroll | 230 |
| | 121 |
| | 26 |
| | 15 |
| | 15 |
| | 26 |
| | 6 |
| | 4 |
| | 2 |
|
| Other | 58 |
| | 39 |
| | 2 |
| | — |
| | 4 |
| | 7 |
| | 3 |
| | 3 |
| | 1 |
|
| Total taxes other than income | $ | 1,731 |
| | $ | 555 |
| | $ | 296 |
| | $ | 154 |
| | $ | 240 |
|
| $ | 452 |
| | $ | 371 |
|
| $ | 57 |
|
| $ | 6 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | Successor | | Predecessor |
| | For the year ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | January 1, 2016 to March 23, 2016 |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | PHI |
| Taxes other than income | | | | | | | | | | | | | | | | | | | |
Utility(a) | $ | 753 |
| | $ | 122 |
| | $ | 242 |
| | $ | 136 |
| | $ | 85 |
| | $ | 312 |
| | $ | 18 |
| | $ | — |
| | $ | 253 |
| | $ | 78 |
|
| Property | 483 |
| | 246 |
| | 27 |
| | 13 |
| | 123 |
| | 53 |
| | 31 |
| | 3 |
| | 73 |
| | 18 |
|
| Payroll | 226 |
| | 117 |
| | 28 |
| | 15 |
| | 17 |
| | 8 |
| | 5 |
| | 3 |
| | 23 |
| | 8 |
|
| Other | 114 |
| | 21 |
| | (4 | ) | | — |
| | 4 |
| | 4 |
| | 1 |
| | 1 |
| | 5 |
| | 1 |
|
| Total taxes other than income | $ | 1,576 |
| | $ | 506 |
| | $ | 293 |
| | $ | 164 |
| | $ | 229 |
|
| $ | 377 |
|
| $ | 55 |
|
| $ | 7 |
|
| $ | 354 |
| | $ | 105 |
|
__________
| |
(a) | Generation’s utility tax represents gross receipts tax related to its retail operations and ComEd’s, PECO’s, BGE’s, Pepco's, DPL's and ACE's utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
(b)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
(c)Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter of 2020 and were fair valued based on quoted market prices of the stocks as of December 31, 2020.
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Depreciation, amortization, and accretion |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | | | | | | |
Property, plant, and equipment(a) | $ | 4,364 | | | $ | 2,070 | | | $ | 922 | | | $ | 319 | | | $ | 397 | | | $ | 586 | | | $ | 257 | | | $ | 155 | | | $ | 140 | |
Amortization of regulatory assets(a) | 588 | | | 0 | | | 211 | | | 28 | | | 153 | | | 196 | | | 120 | | | 36 | | | 40 | |
Amortization of intangible assets, net(a) | 62 | | | 53 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Amortization of energy contract assets and liabilities(b) | 30 | | | 30 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Nuclear fuel(c) | 983 | | | 983 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
ARO accretion(d) | 500 | | | 500 | | | 0 | | | 0 | | | — | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total depreciation, amortization, and accretion | $ | 6,527 | | | $ | 3,636 | | | $ | 1,133 | | | $ | 347 | | | $ | 550 | | | $ | 782 | | | $ | 377 | | | $ | 191 | | | $ | 180 | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2019 | | | | | | | | | | | | | | | | |
Property, plant, and equipment(a) | $ | 3,665 | | | $ | 1,485 | | | $ | 886 | | | $ | 303 | | | $ | 359 | | | $ | 547 | | | $ | 239 | | | $ | 146 | | | $ | 123 | |
Amortization of regulatory assets(a) | 528 | | | 0 | | | 147 | | | 30 | | | 143 | | | 207 | | | 135 | | | 38 | | | 34 | |
Amortization of intangible assets, net(a) | 59 | | | 50 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Amortization of energy contract assets and liabilities(b) | 21 | | | 21 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Nuclear fuel(c) | 1,016 | | | 1,016 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
ARO accretion(d) | 491 | | | 491 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total depreciation, amortization, and accretion | $ | 5,780 | | | $ | 3,063 | | | $ | 1,033 | | | $ | 333 | | | $ | 502 | | | $ | 754 | | | $ | 374 | | | $ | 184 | | | $ | 157 | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2018 | | | | | | | | | | | | | | | | |
Property, plant, and equipment(a) | $ | 3,740 | | | $ | 1,748 | | | $ | 820 | | | $ | 274 | | | $ | 335 | | | $ | 480 | | | $ | 218 | | | $ | 131 | | | $ | 94 | |
Amortization of regulatory assets(a) | 555 | | | 0 | | | 120 | | | 27 | | | 148 | | | 260 | | | 167 | | | 51 | | | 42 | |
Amortization of intangible assets, net(a) | 58 | | | 49 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Amortization of energy contract assets and liabilities(b) | 14 | | | 14 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Nuclear fuel(c) | 1,115 | | | 1,115 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
ARO accretion(d) | 489 | | | 489 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total depreciation, amortization, and accretion | $ | 5,971 | | | $ | 3,415 | | | $ | 940 | | | $ | 301 | | | $ | 483 | | | $ | 740 | | | $ | 385 | | | $ | 182 | | | $ | 136 | |
__________
(a)Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(b)Included in Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(c)Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the year ended December 31, 2018 |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Other, Net | | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | $ | 506 |
| | $ | 506 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Non-regulatory agreement units | 302 |
| | 302 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net unrealized losses on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | (715 | ) | | (715 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Non-regulatory agreement units | (483 | ) | | (483 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net unrealized losses on pledged assets | | | | | | | | | | | | | | | | | |
| Zion Station decommissioning | (8 | ) | | (8 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Regulatory offset to NDT fund-related activities(b) | 171 |
| | 171 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total decommissioning-related activities | (227 | ) |
| (227 | ) |
| — |
|
| — |
|
| — |
| | — |
|
| — |
|
| — |
|
| — |
|
| Investment income | 43 |
| | 32 |
| | — |
| | 1 |
| | 1 |
| | 4 |
| | 2 |
| | 1 |
| | — |
|
| Interest income related to uncertain income tax positions | 5 |
| | 1 |
|
| — |
|
| — |
|
| — |
| | — |
| | — |
| | — |
| | — |
|
| AFUDC—Equity | 69 |
| | — |
| | 19 |
| | 7 |
| | 18 |
| | 25 |
| | 22 |
| | 2 |
| | 1 |
|
| Non-service net periodic benefit cost | (47 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | 45 |
| | 16 |
| | 14 |
| | — |
| | — |
| | 14 |
| | 7 |
| | 7 |
| | 1 |
|
| Other, net | $ | (112 | ) |
| $ | (178 | ) |
| $ | 33 |
|
| $ | 8 |
|
| $ | 19 |
| | $ | 43 |
|
| $ | 31 |
|
| $ | 10 |
|
| $ | 2 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
(d)Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash paid (refunded) during the year: |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | |
| Interest (net of amount capitalized) | $ | 1,521 | | | $ | 331 | | | $ | 371 | | | $ | 144 | | | $ | 125 | | | $ | 257 | | | $ | 129 | | | $ | 61 | | | $ | 57 | |
| Income taxes (net of refunds) | 10 | | | 70 | | | (61) | | | (37) | | | (57) | | | 46 | | | 40 | | | 12 | | | (3) | |
| For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | |
| Interest (net of amount capitalized) | $ | 1,470 | | | $ | 373 | | | $ | 343 | | | $ | 129 | | | $ | 106 | | | $ | 255 | | | $ | 130 | | | $ | 59 | | | $ | 55 | |
| Income taxes (net of refunds) | 265 | | | (44) | | | (42) | | | 82 | | | 17 | | | 29 | | | 7 | | | 19 | | | (5) | |
| For the year ended December 31, 2018 | | | | | | | | | | | | | | | | | |
| Interest (net of amount capitalized) | $ | 1,421 | | | $ | 369 | | | $ | 332 | | | $ | 125 | | | $ | 94 | | | $ | 250 | | | $ | 123 | | | $ | 56 | | | $ | 61 | |
| Income taxes (net of refunds) | 95 | | | 746 | | | (153) | | | (2) | | | 14 | | | (32) | | | 41 | | | (6) | | | (12) | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the year ended December 31, 2017 |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Other, Net | | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | $ | 488 |
| | $ | 488 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Non-regulatory agreement units | 209 |
| | 209 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | 455 |
| | 455 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Non-regulatory agreement units | 521 |
| | 521 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net unrealized losses on pledged assets | | | | | | | | | | | | | | | | | |
| Zion Station decommissioning | (10 | ) | | (10 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Regulatory offset to NDT fund-related activities(b) | (724 | ) | | (724 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total decommissioning-related activities | 939 |
|
| 939 |
|
| — |
|
| — |
|
| — |
|
| — |
| | — |
|
| — |
|
| — |
|
| Investment income | 8 |
| | 6 |
| | — |
| | — |
| | — |
| | 2 |
| | 1 |
| | — |
| | — |
|
| Interest income (expense) related to uncertain income tax positions | 3 |
|
| (1 | ) |
| — |
|
| — |
|
| — |
| | — |
| | — |
| | — |
| | — |
|
Benefit related to uncertain income tax positions(c) | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| AFUDC—Equity | 73 |
| | — |
| | 12 |
| | 9 |
| | 16 |
| | 36 |
| | 23 |
| | 7 |
| | 6 |
|
| Non-service net periodic benefit cost | (109 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | 31 |
| | 4 |
| | 10 |
| | — |
| | — |
| | 16 |
| | 8 |
| | 7 |
| | 1 |
|
| Other, net | $ | 947 |
|
| $ | 948 |
|
| $ | 22 |
|
| $ | 9 |
|
| $ | 16 |
|
| $ | 54 |
| | $ | 32 |
|
| $ | 14 |
|
| $ | 7 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other non-cash operating activities: |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| For the year ended December 31, 2020 | | | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 411 | | | $ | 115 | | | $ | 114 | | | $ | 5 | | | $ | 62 | | | $ | 70 | | | $ | 15 | | | $ | 7 | | | $ | 14 | |
| Allowance for credit losses | 150 | | | 17 | | | 32 | | | 42 | | | 15 | | | 43 | | | 24 | | | 16 | | | 2 | |
Other decommissioning-related activity(a) | (659) | | | (659) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Energy-related options(b) | 104 | | | 104 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
True-up adjustments to decoupling mechanisms and formula rates(c) | (6) | | | 0 | | | 47 | | | (16) | | | (16) | | | (21) | | | (40) | | | 7 | | | 12 | |
| Severance costs | 105 | | | 90 | | | 1 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Provision for excess and obsolete inventory | 131 | | | 128 | | | 2 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Long-term incentive plan | 56 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Amortization of operating ROU asset | 222 | | | 155 | | | 2 | | | 1 | | | 31 | | | 28 | | | 7 | | | 8 | | | 3 | |
| Asset impairments | 0 | | | 0 | | | 15 | | | 0 | | | 0 | | | 13 | | | 0 | | | 7 | | | 6 | |
| | | | | | | | | | | | | | | | | |
| AFUDC - Equity | (104) | | | 0 | | | (29) | | | (17) | | | (22) | | | (36) | | | (28) | | | (4) | | | (4) | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2019 | | | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 438 | | | $ | 135 | | | $ | 96 | | | $ | 12 | | | $ | 61 | | | $ | 95 | | | $ | 25 | | | $ | 15 | | | $ | 16 | |
| Allowance for credit losses | 120 | | | 31 | | | 33 | | | 31 | | | 8 | | | 17 | | | 7 | | | 4 | | | 5 | |
Other decommissioning-related activity(a) | (506) | | | (506) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Energy-related options(b) | 22 | | | 22 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
True-up adjustments to decoupling mechanisms and formula rates(d) | 124 | | | 0 | | | 128 | | | 0 | | | 0 | | | (4) | | | (4) | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Long-term incentive plan | 10 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Amortization of operating ROU asset | 244 | | | 172 | | | 3 | | | 0 | | | 30 | | | 33 | | | 8 | | | 8 | | | 4 | |
| Change in environmental liabilities | 23 | | | 0 | | | 0 | | | 0 | | | 0 | | | 23 | | | 23 | | | 0 | | | 0 | |
| AFUDC - Equity | (85) | | | 0 | | | (17) | | | (13) | | | (21) | | | (34) | | | (25) | | | (4) | | | (5) | |
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2018 | | | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 583 | | | $ | 204 | | | $ | 177 | | | $ | 18 | | | $ | 59 | | | $ | 67 | | | $ | 15 | | | $ | 6 | | | $ | 12 | |
| Allowance for credit losses | 159 | | | 48 | | | 40 | | | 33 | | | 10 | | | 28 | | | 11 | | | 6 | | | 11 | |
Other decommissioning-related activity(a) | (2) | | | (2) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Energy-related options(b) | 10 | | | 10 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
True-up adjustments to decoupling mechanisms and formula rates(d) | 49 | | | 0 | | | 28 | | | 0 | | | 0 | | | 21 | | | 21 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Asset retirement costs | 20 | | | 0 | | | 0 | | | 0 | | | 0 | | | 20 | | | 22 | | | (1) | | | (1) | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Long-term incentive plan | 140 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| AFUDC - Equity | (69) | | | 0 | | | (19) | | | (7) | | | (18) | | | (25) | | | (22) | | | (2) | | | (1) | |
__________
(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO updates and accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| | For the year ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
| Other, Net | | | | | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | $ | 237 |
| | $ | 237 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
| Non-regulatory agreement units | 126 |
| | 126 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | 216 |
| | 216 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Non-regulatory agreement units | 194 |
| | 194 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Net unrealized losses on pledged assets | | | | | | | | | | | | | | | | | | | | |
| Zion Station decommissioning | (1 | ) | | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Regulatory offset to NDT fund-related activities(b) | (372 | ) | | (372 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Total decommissioning-related activities | 400 |
|
| 400 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| | — |
| | | — |
|
| Investment income (loss) | 17 |
| | 8 |
| | — |
| | (1 | ) | | 2 |
| | 1 |
| | — |
| | 1 |
| | 1 |
| | | — |
|
| Long-term lease income | 4 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Interest income (expense) related to uncertain income tax positions | 13 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | (1 | ) | | | — |
|
Penalty related to uncertain income tax positions(c) | (106 | ) | | — |
| | (86 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| AFUDC—Equity | 64 |
| | — |
| | 14 |
| | 8 |
| | 19 |
| | 19 |
| | 5 |
| | 6 |
| | 23 |
| | | 7 |
|
| Non-service net periodic benefit cost | (116 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Loss on debt extinguishment | (3 | ) | | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Other | 24 |
| | (5 | ) | | 7 |
| | 1 |
| | — |
| | 15 |
| | 8 |
| | 2 |
| | 21 |
| | | (11 | ) |
| Other, net | $ | 297 |
|
| $ | 401 |
|
| $ | (65 | ) |
| $ | 8 |
|
| $ | 21 |
|
| $ | 36 |
|
| $ | 13 |
|
| $ | 9 |
| | $ | 44 |
| | | $ | (4 | ) |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
__________
| |
(a) | Includes investment income and realized gains and losses on sales of investments within the NDT funds. |
| |
(b) | Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for these units. See Note 15Note 24 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. |
| |
(c) | See Note 14—Income Taxes for additional information on the penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position. |
Supplemental Cash FlowFinancial Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the year ended December 31, 2018 |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Depreciation, amortization and accretion | | | | | | | | | | | | | | | | | |
| Property, plant and equipment | $ | 3,740 |
| | $ | 1,748 |
| | $ | 820 |
| | $ | 274 |
| | $ | 335 |
| | $ | 480 |
| | $ | 218 |
| | $ | 131 |
| | $ | 94 |
|
| Regulatory assets | 555 |
| | — |
| | 120 |
| | 27 |
| | 148 |
| | 260 |
| | 167 |
| | 51 |
| | 42 |
|
| Amortization of intangible assets, net | 58 |
| | 49 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of energy contract assets and liabilities(a) | 14 |
| | 14 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Nuclear fuel(b) | 1,115 |
| | 1,115 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
ARO accretion(c) | 489 |
| | 489 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total depreciation, amortization and accretion | $ | 5,971 |
| | $ | 3,415 |
| | $ | 940 |
|
| $ | 301 |
| | $ | 483 |
|
| $ | 740 |
| | $ | 385 |
|
| $ | 182 |
|
| $ | 136 |
|
(d)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution and energy efficiency formula rates. For Pepco and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms. See Note 3 — Regulatory Matters for additional information. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the year ended December 31, 2017 |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Depreciation, amortization and accretion | | | | | | | | | | | | | | | | | |
| Property, plant and equipment | $ | 3,293 |
| | $ | 1,409 |
| | $ | 777 |
| | $ | 261 |
| | $ | 312 |
| | $ | 457 |
| | $ | 203 |
| | $ | 124 |
| | $ | 89 |
|
| Regulatory assets | 478 |
| | — |
| | 73 |
| | 25 |
| | 161 |
| | 218 |
| | 118 |
| | 43 |
| | 57 |
|
| Amortization of intangible assets, net | 57 |
| | 48 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of energy contract assets and liabilities(a) | 35 |
| | 35 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Nuclear fuel(b) | 1,096 |
| | 1,096 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
ARO accretion(c) | 468 |
| | 468 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total depreciation, amortization and accretion | $ | 5,427 |
|
| $ | 3,056 |
|
| $ | 850 |
|
| $ | 286 |
|
| $ | 473 |
|
| $ | 675 |
| | $ | 321 |
|
| $ | 167 |
|
| $ | 146 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| | For the year ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
| Depreciation, amortization and accretion | | | | | | | | | | | | | | | | |
| Property, plant and equipment | $ | 3,477 |
| | $ | 1,835 |
| | $ | 708 |
| | $ | 244 |
| | $ | 299 |
| | $ | 175 |
| | $ | 110 |
| | $ | 82 |
| | $ | 325 |
| | | $ | 94 |
|
| Regulatory assets | 407 |
| | — |
| | 67 |
| | 26 |
| | 124 |
| | 120 |
| | 47 |
| | 83 |
| | 190 |
| | | 58 |
|
| Amortization of intangible assets, net | 52 |
| | 44 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Amortization of energy contract assets and liabilities(a) | 35 |
| | 35 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Nuclear fuel(b) | 1,159 |
| | 1,159 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
ARO accretion(c) | 446 |
| | 446 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Total depreciation, amortization and accretion | $ | 5,576 |
| | $ | 3,519 |
|
| $ | 775 |
|
| $ | 270 |
|
| $ | 423 |
|
| $ | 295 |
|
| $ | 157 |
|
| $ | 165 |
| | $ | 515 |
| | | $ | 152 |
|
__________
| |
(a) | Included in Operating revenues or Purchased power and fuel in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
| |
(b) | Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
| |
(c) | Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the year ended December 31, 2018 |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Cash paid (refunded) during the year: | | | | | | | | | | | | | | | | | |
| Interest (net of amount capitalized) | $ | 1,421 |
| | $ | 369 |
| | $ | 332 |
| | $ | 125 |
| | $ | 94 |
| | $ | 250 |
| | $ | 123 |
| | $ | 56 |
| | $ | 61 |
|
| Income taxes (net of refunds) | 95 |
| | 746 |
| | (153 | ) | | (2 | ) | | 14 |
| | (32 | ) | | 41 |
| | (6 | ) | | (12 | ) |
| Other non-cash operating activities: | | | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 583 |
| | $ | 204 |
| | $ | 177 |
| | $ | 18 |
| | $ | 59 |
| | $ | 67 |
| | $ | 15 |
| | $ | 6 |
| | $ | 12 |
|
| Loss (gain) from equity method investments | 28 |
| | 30 |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
|
| Provision for uncollectible accounts | 159 |
| | 48 |
| | 40 |
| | 33 |
| | 10 |
| | 28 |
| | 11 |
| | 6 |
| | 11 |
|
| Provision for excess and obsolete inventory | 24 |
| | 20 |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Stock-based compensation costs | 75 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other decommissioning-related activity(a) | (2 | ) | | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy-related options(b) | 10 |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Amortization of regulatory asset related to debt costs | 8 |
| | — |
| | 3 |
| | 1 |
| | — |
| | 4 |
| | 2 |
| | 1 |
| | 1 |
|
| Amortization of rate stabilization deferral | 14 |
| | — |
| | — |
| | — |
| | — |
| | 14 |
| | 14 |
| | — |
| | — |
|
| Amortization of debt fair value adjustment | (15 | ) | | (12 | ) | | — |
| | — |
| | — |
| | (3 | ) | | — |
| | — |
| | — |
|
Merger-related commitments(c) | — |
| | — |
| | — |
| | — |
| | — |
| | 5 |
| | — |
| | 5 |
| | — |
|
| Severance costs | 35 |
| | 9 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Asset retirement costs | 20 |
| | — |
| | — |
| | — |
| | — |
| | 20 |
| | 22 |
| | (1 | ) | | (1 | ) |
| Amortization of debt costs | 36 |
| | 14 |
| | 5 |
| | 2 |
| | 1 |
| | 3 |
| | 2 |
| | — |
| | 1 |
|
Discrete impacts from EIMA and FEJA(d) | 28 |
| | — |
| | 28 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Long-term incentive plan | 140 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | (19 | ) | | (23 | ) | | (14 | ) | | (3 | ) | | (12 | ) | | 6 |
| | (6 | ) | | 7 |
| | — |
|
| Total other non-cash operating activities | $ | 1,124 |
|
| $ | 298 |
|
| $ | 242 |
|
| $ | 51 |
|
| $ | 58 |
|
| $ | 143 |
| | $ | 60 |
| | $ | 24 |
| | $ | 24 |
|
| Non-cash investing and financing activities: | | | | | | | | | | | | | | | | | |
| Change in capital expenditures not paid | $ | (69 | ) | | $ | (199 | ) | | $ | 11 |
| | $ | (12 | ) | | $ | 50 |
| | $ | 93 |
| | $ | 20 |
| | $ | 22 |
| | $ | 46 |
|
| Change in PPE related to ARO update | (107 | ) | | (130 | ) | | 7 |
| | — |
| | 1 |
| | 15 |
| | 12 |
| | 2 |
| | 1 |
|
| Dividends on stock compensation | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Acquisition of land | 3 |
| | — |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
__________
| |
(a) | Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. |
| |
(b) | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. |
| |
(c) | See Note 5 - Mergers, Acquisitions and Dispositions for additional information. |
| |
(d) | Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 4 — Regulatory Matters for additional information. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the year ended December 31, 2017 |
| | | | | | | | | | | | Successor | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Cash paid (refunded) during the year: | | | | | | | | | | | | | | | | | |
| Interest (net of amount capitalized) | $ | 2,430 |
| | $ | 391 |
| | $ | 307 |
| | $ | 103 |
| | $ | 96 |
| | $ | 236 |
| | $ | 114 |
| | $ | 49 |
| | $ | 59 |
|
| Income taxes (net of refunds) | 540 |
| | 337 |
| | 83 |
| | 47 |
| | (2 | ) | | (144 | ) | | (104 | ) | | (49 | ) | | (2 | ) |
| Other non-cash operating activities: | | | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 643 |
| | $ | 227 |
| | $ | 176 |
| | $ | 29 |
| | $ | 62 |
| | $ | 94 |
| | $ | 25 |
| | $ | 13 |
| | $ | 13 |
|
| Loss (gain) from equity method investments | 32 |
| | 33 |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
|
| Provision for uncollectible accounts | 125 |
| | 38 |
| | 34 |
| | 26 |
| | 8 |
| | 19 |
| | 8 |
| | 3 |
| | 8 |
|
| Provision for excess and obsolete inventory | 56 |
| | 51 |
| | 3 |
| | — |
| | — |
| | 2 |
| | 1 |
| | 1 |
| | — |
|
| Stock-based compensation costs | 88 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other decommissioning-related activity(a) | (313 | ) | | (313 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy-related options(b) | 7 |
| | 7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Amortization of regulatory asset related to debt costs | 9 |
| | — |
| | 4 |
| | 1 |
| | — |
| | 4 |
| | 2 |
| | 1 |
| | 1 |
|
| Amortization of rate stabilization deferral | (10 | ) | | — |
| | — |
| | — |
| | 7 |
| | (17 | ) | | (17 | ) | | — |
| | — |
|
| Amortization of debt fair value adjustment | (18 | ) | | (12 | ) | | — |
| | — |
| | — |
| | (6 | ) | | — |
| | — |
| | — |
|
Merger-related commitments(c) | — |
| | — |
| | — |
| | — |
| | — |
| | (8 | ) | | (6 | ) | | (2 | ) | | — |
|
| Severance costs | 35 |
| | 31 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
| Amortization of debt costs | 64 |
| | 37 |
| | 5 |
| | 2 |
| | 2 |
| | 4 |
| | 2 |
| | — |
| | 1 |
|
Discrete impacts from EIMA and FEJA(d) | (52 | ) | | — |
| | (52 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Vacation accrual adjustment(e) | (68 | ) | | (35 | ) | | (12 | ) | | — |
| | — |
| | (8 | ) | | (8 | ) | | — |
| | — |
|
| Long-term incentive plan | 109 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Change in environmental liabilities | 44 |
| | 44 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | (30 | ) | | 4 |
| | 6 |
| | (4 | ) | | (14 | ) | | (28 | ) | | (13 | ) | | (7 | ) | | (6 | ) |
| Total other non-cash operating activities | $ | 721 |
|
| $ | 112 |
|
| $ | 164 |
|
| $ | 54 |
|
| $ | 65 |
| | $ | 58 |
|
| $ | (6 | ) |
| $ | 9 |
|
| $ | 17 |
|
| Non-cash investing and financing activities: | | | | | | | | | | | | | | | | | |
| Change in capital expenditures not paid | $ | 42 |
| | $ | 73 |
| | $ | (61 | ) | | $ | 22 |
| | $ | 23 |
| | $ | (12 | ) | | $ | 5 |
| | $ | 4 |
| | $ | (13 | ) |
| Change in PPE related to ARO update | 29 |
| | 29 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Non-cash financing of capital projects | 16 |
| | 16 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Indemnification of like-kind exchange position(f) | — |
| | — |
| | 21 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Dividends on stock compensation | 7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Dissolution of financing trust due to long-term debt retirement | 8 |
| | — |
| | — |
| | — |
| | 8 |
| | — |
| | — |
| | — |
| | — |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Fair value adjustment of long-term debt due to retirement | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Fair value of pension and OPEB obligation transferred in connection with FitzPatrick | — |
| | 33 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
__________
| |
(a) | Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. |
| |
(b) | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. |
| |
(c) | See Note 5 - Mergers, Acquisitions and Dispositions for additional information. |
| |
(d) | Reflects the change in ComEd's distribution and energy efficiency formula rates . See Note 4 — Regulatory Matters for additional information. |
| |
(e) | On December 1, 2017, Exelon adopted a single, standard vacation accrual policy for all non-represented, non-craft (represented and craft policies remained unchanged) employees effective January 1, 2018. To reflect the new policy, Exelon recorded a one-time, $68 million pre-tax credit to expense to reverse 2018 vacation cost originally accrued throughout 2017 that will now be accrued ratably over the year in 2018. |
| |
(f) | See Note 14 — Income Taxes for additional information on the like-kind exchange tax position. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| | For the year ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
| Cash paid (refunded) during the year: | | | | | | | | | | | | | | | | | | | | |
| Interest (net of amount capitalized) | $ | 1,340 |
| | $ | 339 |
| | $ | 298 |
| | $ | 104 |
| | $ | 92 |
| | $ | 118 |
| | $ | 47 |
| | $ | 62 |
| | $ | 209 |
| | | $ | 43 |
|
| Income taxes (net of refunds) | (441 | ) | | 435 |
| | (444 | ) | | 64 |
| | 31 |
| | 216 |
| | 115 |
| | 200 |
| | 258 |
| | | 11 |
|
| Other non-cash operating activities: | | | | | | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 619 |
| | $ | 218 |
| | $ | 166 |
| | $ | 33 |
| | $ | 67 |
| | $ | 31 |
| | $ | 18 |
| | $ | 15 |
| | $ | 86 |
| | | $ | 23 |
|
| Loss from equity method investments | 24 |
| | 25 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Provision for uncollectible accounts | 155 |
| | 19 |
| | 41 |
| | 30 |
| | 1 |
| | 29 |
| | 23 |
| | 32 |
| | 65 |
| | | 16 |
|
| Stock-based compensation costs | 111 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | 3 |
|
Other decommissioning-related activity(a) | (384 | ) | | (384 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Energy-related options(b) | (11 | ) | | (11 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Amortization of regulatory asset related to debt costs | 9 |
| | — |
| | 4 |
| | 1 |
| | — |
| | 2 |
| | 1 |
| | 1 |
| | 3 |
| | | 1 |
|
| Amortization of rate stabilization deferral | 76 |
| | — |
| | — |
| | — |
| | 81 |
| | (12 | ) | | 2 |
| | — |
| | (5 | ) | | | 5 |
|
| Amortization of debt fair value adjustment | (11 | ) | | (11 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Merger-related commitments(c)(d) | 558 |
| | 53 |
| | — |
| | — |
| | — |
| | 125 |
| | 82 |
| | 110 |
| | 317 |
| | | — |
|
| Severance costs | 99 |
| | 22 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 56 |
| | | — |
|
Discrete impacts from EIMA(e) | 8 |
| | — |
| | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Amortization of debt costs | 35 |
| | 17 |
| | 4 |
| | 3 |
| | 1 |
| | — |
| | — |
| | — |
| | 1 |
| | | — |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Provision for excess and obsolete inventory | 12 |
| | 6 |
| | 4 |
| | — |
| | — |
| | 3 |
| | 1 |
| | 1 |
| | 1 |
| | | 1 |
|
| Lower of cost or market inventory adjustment | 37 |
| | 36 |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Baltimore City Conduit Lease Settlement | (28 | ) | | — |
| | — |
| | — |
| | (28 | ) | | — |
| | — |
| | — |
| | — |
| | | — |
|
| Cash Working Capital Order | (13 | ) | | — |
| | — |
| | — |
| | (13 | ) | | — |
| | — |
| | — |
| | — |
| | | — |
|
| Asset retirement costs | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | 2 |
| | 2 |
| | | — |
|
| Long-term incentive plan | 70 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Other | (35 | ) | | 25 |
| | (12 | ) | | (3 | ) | | (21 | ) | | (3 | ) | | (14 | ) | | (6 | ) | | (11 | ) | | | (3 | ) |
| Total other non-cash operating activities | $ | 1,333 |
|
| $ | 15 |
|
| $ | 215 |
|
| $ | 65 |
|
| $ | 88 |
|
| $ | 175 |
| | $ | 114 |
| | $ | 155 |
| | $ | 515 |
| | | $ | 46 |
|
| Non-cash investing and financing activities: | | | | | | | | | | | | | | | | | | | | |
| Change in capital expenditures not paid | $ | (128 | ) | | $ | 50 |
| | $ | (91 | ) | | $ | (11 | ) | | $ | (86 | ) | | $ | 27 |
| | $ | (12 | ) | | $ | 11 |
| | $ | 21 |
| | | $ | 11 |
|
| Change in PPE related to ARO update | 191 |
| | 191 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Indemnification of like-kind exchange position(g) | — |
| | — |
| | 158 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Dividends on stock compensation | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Non-cash financing of capital projects | 95 |
| | 95 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Sale of Upstream assets(c) | 37 |
| | 37 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Pending FitzPatrick Acquisition(h) | (54 | ) | | (54 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
| Fair value of net assets contributed to Generation in connection with the PHI merger, net of cash | — |
| | 119 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash(c)(f) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 127 |
| | | — |
|
Fair value of pension obligation transferred in connection with the PHI Merger, net of cash(c)(f) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 53 |
| | | — |
|
| Assumption of member purchase liability | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 29 |
| | | — |
|
| Assumption of merger commitment liability | — |
| | — |
| | — |
| | — |
| | — |
| | 33 |
| | — |
| | — |
| | 33 |
| | | — |
|
__________
| |
(a) | Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. |
| |
(b) | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. |
| |
(c) | See Note 5 - Mergers, Acquisitions and Dispositions for additional information. |
| |
(d) | Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts. |
| |
(e) | Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate. See Note 4 — Regulatory Matters for additional information. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(f) | Immediately following closing of the PHI Merger, the net assets associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation. |
| |
(g) | See Note 14 — Income Taxes for additional information on the like-kind exchange tax position. |
| |
(h) | Reflects the transfer of nuclear fuel to Entergy under the cost reimbursement provisions of the FitzPatrick acquisition agreements. See Note 5 - Mergers, Acquisitions and Dispositions for additional information. |
The following tables provide a reconciliation of cash, restricted cash, and cash equivalents and restricted cash reported within the Registrants' Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
| | | | | | | | | | | | | | | | | | | | | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| | | | | | | | | | | | Successor | | | | | | | |
| December 31, 2020 | | December 31, 2020 | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | Cash and cash equivalents | $ | 663 | | | $ | 226 | | | $ | 83 | | | $ | 19 | | | $ | 144 | | | $ | 111 | | | $ | 30 | | | $ | 15 | | | $ | 17 | |
| Restricted cash and cash equivalents | | Restricted cash and cash equivalents | 438 | | | 89 | | | 279 | | | 7 | | | 1 | | | 39 | | | 35 | | | 0 | | | 3 | |
| Restricted cash included in other long-term assets | | Restricted cash included in other long-term assets | 53 | | | 0 | | | 43 | | | 0 | | | 0 | | | 10 | | | 0 | | | 0 | | | 10 | |
| Cash, restricted cash, and cash equivalents - Held for Sale | | Cash, restricted cash, and cash equivalents - Held for Sale | 12 | | | 12 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total cash, restricted cash, and cash equivalents | | Total cash, restricted cash, and cash equivalents | $ | 1,166 | | | $ | 327 | | | $ | 405 | | | $ | 26 | | | $ | 145 | | | $ | 160 | | | $ | 65 | | | $ | 15 | | | $ | 30 | |
| December 31, 2019 | | December 31, 2019 | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | Cash and cash equivalents | $ | 587 | | | $ | 303 | | | $ | 90 | | | $ | 21 | | | $ | 24 | | | $ | 131 | | | $ | 30 | | | $ | 13 | | | $ | 12 | |
| Restricted cash and cash equivalents | | Restricted cash and cash equivalents | 358 | | | 146 | | | 150 | | | 6 | | | 1 | | | 36 | | | 33 | | | 0 | | | 2 | |
| Restricted cash included in other long-term assets | | Restricted cash included in other long-term assets | 177 | | | 0 | | | 163 | | | 0 | | | 0 | | | 14 | | | 0 | | | 0 | | | 14 | |
| Total cash, restricted cash, and cash equivalents | | Total cash, restricted cash, and cash equivalents | $ | 1,122 | | | $ | 449 | | | $ | 403 | | | $ | 27 | | | $ | 25 | | | $ | 181 | | | $ | 63 | | | $ | 13 | | | $ | 28 | |
| December 31, 2018 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | December 31, 2018 | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 1,349 |
| | $ | 750 |
| | $ | 135 |
| | $ | 130 |
| | $ | 7 |
| | $ | 124 |
| | $ | 16 |
| | $ | 23 |
| | $ | 7 |
| Cash and cash equivalents | $ | 1,349 | | | $ | 750 | | | $ | 135 | | | $ | 130 | | | $ | 7 | | | $ | 124 | | | $ | 16 | | | $ | 23 | | | $ | 7 | |
| Restricted cash | 247 |
| | 153 |
| | 29 |
| | 5 |
| | 6 |
| | 43 |
| | 37 |
| | 1 |
| | 4 |
| |
| Restricted cash and cash equivalents | | Restricted cash and cash equivalents | 247 | | | 153 | | | 29 | | | 5 | | | 6 | | | 43 | | | 37 | | | 1 | | | 4 | |
| Restricted cash included in other long-term assets | 185 |
| | — |
| | 166 |
| | — |
| | — |
| | 19 |
| | — |
| | — |
| | 19 |
| Restricted cash included in other long-term assets | 185 | | | 0 | | | 166 | | | 0 | | | 0 | | | 19 | | | 0 | | | 0 | | | 19 | |
| Total cash, cash equivalents and restricted cash | $ | 1,781 |
| | $ | 903 |
| | $ | 330 |
| | $ | 135 |
| | $ | 13 |
| | $ | 186 |
| | $ | 53 |
| | $ | 24 |
| | $ | 30 |
| |
| Total cash, restricted cash, and cash equivalents | | Total cash, restricted cash, and cash equivalents | $ | 1,781 | | | $ | 903 | | | $ | 330 | | | $ | 135 | | | $ | 13 | | | $ | 186 | | | $ | 53 | | | $ | 24 | | | $ | 30 | |
| December 31, 2017 | | December 31, 2017 | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | Cash and cash equivalents | $ | 898 | | | $ | 416 | | | $ | 76 | | | $ | 271 | | | $ | 17 | | | $ | 30 | | | $ | 5 | | | $ | 2 | | | $ | 2 | |
| Restricted cash and cash equivalents | | Restricted cash and cash equivalents | 207 | | | 138 | | | 5 | | | 4 | | | 1 | | | 42 | | | 35 | | | 0 | | | 6 | |
| Restricted cash included in other long-term assets | | Restricted cash included in other long-term assets | 85 | | | 0 | | | 63 | | | 0 | | | 0 | | | 23 | | | 0 | | | 0 | | | 23 | |
| Total cash, restricted cash, and cash equivalents | | Total cash, restricted cash, and cash equivalents | $ | 1,190 | | | $ | 554 | | | $ | 144 | | | $ | 275 | | | $ | 18 | | | $ | 95 | | | $ | 40 | | | $ | 2 | | | $ | 31 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Successor | | | | | | |
| December 31, 2017 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Cash and cash equivalents | $ | 898 |
| | $ | 416 |
| | $ | 76 |
| | $ | 271 |
| | $ | 17 |
| | $ | 30 |
| | $ | 5 |
| | $ | 2 |
| | $ | 2 |
|
| Restricted cash | 207 |
| | 138 |
| | 5 |
| | 4 |
| | 1 |
| | 42 |
| | 35 |
| | — |
| | 6 |
|
| Restricted cash included in other long-term assets | 85 |
| | — |
| | 63 |
| | — |
| | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
| Total cash, cash equivalents and restricted cash | $ | 1,190 |
| | $ | 554 |
| | $ | 144 |
| | $ | 275 |
| | $ | 18 |
| | $ | 95 |
| | $ | 40 |
| | $ | 2 |
| | $ | 31 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| | December 31, 2016 | | December 31, 2016 | | | March 23, 2016 |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
| Cash and cash equivalents | $ | 635 |
| | $ | 290 |
| | $ | 56 |
| | $ | 63 |
| | $ | 23 |
| | $ | 9 |
| | $ | 46 |
| | $ | 101 |
| | $ | 170 |
| | | $ | 319 |
|
| Restricted cash | 253 |
| | 158 |
| | 2 |
| | 4 |
| | 24 |
| | 33 |
| | — |
| | 9 |
| | 43 |
| | | 11 |
|
| Restricted cash included in other long-term assets | 26 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | 23 |
| | 23 |
| | | 18 |
|
| Total cash, cash equivalents and restricted cash | $ | 914 |
| | $ | 448 |
| | $ | 58 |
| | $ | 67 |
| | $ | 50 |
| | $ | 42 |
| | $ | 46 |
| | $ | 133 |
| | $ | 236 |
| | | $ | 348 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Predecessor | | | | | | |
| December 31, 2015 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Cash and cash equivalents | $ | 6,502 |
| | $ | 431 |
| | $ | 67 |
| | $ | 295 |
| | $ | 9 |
| | $ | 26 |
| | $ | 5 |
| | $ | 5 |
| | $ | 3 |
|
| Restricted cash | 205 |
| | 123 |
| | 2 |
| | 3 |
| | 24 |
| | 14 |
| | 2 |
| | — |
| | 12 |
|
| Restricted cash included in other long-term assets | 5 |
| | 2 |
| | — |
| | — |
| | 3 |
| | 18 |
| | — |
| | — |
| | 18 |
|
| Total cash, cash equivalents and restricted cash | $ | 6,712 |
| | $ | 556 |
| | $ | 69 |
| | $ | 298 |
| | $ | 36 |
| | $ | 58 |
| | $ | 7 |
| | $ | 5 |
| | $ | 33 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2018 and 2017.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2018 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Unbilled customer revenues(a) | $ | 1,656 |
| | $ | 965 |
| | $ | 223 |
| | $ | 114 |
| | $ | 168 |
| | $ | 186 |
| | $ | 97 |
| | $ | 59 |
| | $ | 30 |
|
Allowance for uncollectible accounts (b) | (319 | ) | | (104 | ) | | (81 | ) | | (61 | ) | | (20 | ) | | (53 | ) | | (21 | ) | | (13 | ) | | (19 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2017 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Unbilled customer revenues(a) | $ | 1,858 |
| | $ | 1,017 |
| | $ | 242 |
| | $ | 162 |
| | $ | 205 |
| | $ | 232 |
| | $ | 133 |
| | $ | 68 |
| | $ | 31 |
|
Allowance for uncollectible
accounts(b) | (322 | ) | | (114 | ) | | (73 | ) | | (56 | ) | | (24 | ) | | (55 | ) | | (21 | ) | | (16 | ) | | (18 | ) |
__________
| |
(a) | Represents unbilled portion of receivables estimated under Exelon’s unbilled critical accounting policy. |
| |
(b) | Includes the estimated allowance for uncollectible accounts on billed customer and other accounts receivable. |
The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participatematerial items recorded in the utilities' consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO and ACE purchase receivables at face value and recover uncollectible accounts expense, including those from alternative retail electric and natural gas supplies, through base distribution rates and a rate rider, respectively. Exelon and the Utility Registrants do not record unbilled commodity receivables under their POR programs. Purchased billed receivables are recorded on a net basis in Exelon’s and the Utility Registrant's Consolidated Statements of Operations and Comprehensive Income and are classified in Other accounts receivable, net in theirRegistrants' Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of December 31, 2018 and 2017.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2018 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Purchased receivables | $ | 313 |
| | $ | 94 |
| | $ | 74 |
| | $ | 61 |
| | $ | 84 |
| | $ | 57 |
| | $ | 8 |
| | $ | 19 |
|
Allowance for uncollectible accounts(a) | (34 | ) | | (17 | ) | | (5 | ) | | (3 | ) | | (9 | ) | | (5 | ) | | (1 | ) | | (3 | ) |
| Purchased receivables, net | $ | 279 |
| | $ | 77 |
| | $ | 69 |
| | $ | 58 |
| | $ | 75 |
| | $ | 52 |
| | $ | 7 |
| | $ | 16 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2017 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Purchased receivables | $ | 298 |
| | $ | 87 |
| | $ | 70 |
| | $ | 58 |
| | $ | 83 |
| | $ | 56 |
| | $ | 9 |
| | $ | 18 |
|
Allowance for uncollectible accounts(a) | (31 | ) | | (14 | ) | | (5 | ) | | (3 | ) | | (9 | ) | | (5 | ) | | (1 | ) | | (3 | ) |
| Purchased receivables, net | $ | 267 |
| | $ | 73 |
| | $ | 65 |
| | $ | 55 |
| | $ | 74 |
| | $ | 51 |
| | $ | 8 |
| | $ | 15 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Investments |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| December 31, 2020 | | | | | | | | | | | | | | | | | |
| Equity method investments: | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Other equity method investments | $ | 81 | | | $ | 65 | | | $ | 6 | | | $ | 8 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | | | | | |
| Other investments: | | | | | | | | | | | | | | | | | |
Employee benefit trusts and investments(a) | 283 | | | 61 | | | 0 | | | 22 | | | 10 | | | 140 | | | 115 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Equity investments without readily determinable fair values | 73 | | | 55 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Other available for sale debt security investments | 3 | | | 3 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Total investments | $ | 440 | | | $ | 184 | | | $ | 6 | | | $ | 30 | | | $ | 10 | | | $ | 140 | | | $ | 115 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | | | | | |
| December 31, 2019 | | | | | | | | | | | | | | | | | |
| Equity method investments: | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Other equity method investments | $ | 92 | | | $ | 71 | | | $ | 6 | | | $ | 8 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | | | | | |
| Other investments: | | | | | | | | | | | | | | | | | |
Employee benefit trusts and investments(a) | 262 | | | 54 | | | 0 | | | 19 | | | 7 | | | 135 | | | 110 | | | 0 | | | 0 | |
| Equity investments without readily determinable fair values | 69 | | | 69 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Other available for sale debt security investments | 41 | | | 41 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Total investments | $ | 464 | | | $ | 235 | | | $ | 6 | | | $ | 27 | | | $ | 7 | | | $ | 135 | | | $ | 110 | | | $ | 0 | | | $ | 0 | |
__________
| |
(a) | For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through a rate rider. BGE, Pepco and DPL recover actual write-offs which are reflected in the POR discount rate. |
(a)The Registrants’ debt and equity security investments are recorded at fair market value.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Accrued expenses |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| December 31, 2020 | | | | | | | | | | | | | | | | | |
Compensation-related accruals(a) | $ | 1,069 | | | $ | 426 | | | $ | 170 | | | $ | 73 | | | $ | 84 | | | $ | 109 | | | $ | 36 | | | $ | 18 | | | $ | 17 | |
| Taxes accrued | 527 | | | 229 | | | 94 | | | 16 | | | 73 | | | 117 | | | 90 | | | 18 | | | 12 | |
| Interest accrued | 331 | | | 44 | | | 109 | | | 37 | | | 46 | | | 51 | | | 26 | | | 7 | | | 12 | |
| December 31, 2019 | | | | | | | | | | | | | | | | | |
Compensation-related accruals(a) | $ | 1,052 | | | $ | 422 | | | $ | 171 | | | $ | 58 | | | $ | 78 | | | $ | 101 | | | $ | 28 | | | $ | 19 | | | $ | 15 | |
| Taxes accrued | 414 | | | 222 | | | 83 | | | 3 | | | 26 | | | 117 | | | 90 | | | 14 | | | 8 | |
| Interest accrued | 337 | | | 65 | | | 110 | | | 37 | | | 46 | | | 49 | | | 23 | | | 8 | | | 12 | |
__________
(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Related Party Transactions
25. Related Party Transactions (All Registrants)
Operating revenues from affiliates
Generation
The following tablestable presents Generation’s Operating revenues from affiliates, which are primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants:
| | | | | | | | | | | | | | | | | |
| | For the Years Ended
December 31, |
| | 2020 | | 2019 | | 2018 |
| Operating revenues from affiliates: | | | | | |
ComEd(a)(b) | $ | 330 | | | $ | 369 | | | $ | 523 | |
PECO(c) | 190 | | | 158 | | | 128 | |
BGE(d) | 315 | | | 289 | | | 260 | |
| PHI | 367 | | | 353 | | | 355 | |
Pepco(e) | 279 | | | 264 | | | 206 | |
DPL(f) | 75 | | | 70 | | | 120 | |
ACE(g) | 13 | | | 19 | | | 29 | |
| Other | 9 | | | 3 | | | 2 | |
| Total operating revenues from affiliates (Generation) | $ | 1,211 | | | $ | 1,172 | | | $ | 1,268 | |
__________
(a)Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd.
(b)For 2020, ComEd’s Purchased power from Generation of $345 million is recorded as Operating revenues from ComEd of $330 million and Purchased power and fuel from ComEd of $15 million at Generation. For 2019, ComEd’s Purchased power from Generation of $376 million is recorded as Operating revenues from ComEd of $369 million and Purchased power and fuel from ComEd of $7 million at Generation.
(c)Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs.
(d)Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.
(e)Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.
(f)Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS commodity programs.
(g)Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.
PHI
PHI’s Operating revenues from affiliates are primarily with BSC for services that PHISCO provides to BSC.
Operating and maintenance expense from affiliates
The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 - Significant Accounting Policies for additional information about Registrants' investments at December 31, 2018regarding BSC and 2017.PHISCO.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2018 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Investments | | | | | | | | | | | | | | | | | |
| Equity method investments: | | | | | | | | | | | | | | | | | |
Financing trusts(a) | $ | 14 |
| | $ | — |
| | $ | 6 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Bloom | 180 |
| | 180 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| NET Power | 70 |
| | 70 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other equity method investments | 3 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total equity method investments | 267 |
|
| 251 |
|
| 6 |
|
| 8 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| Other investments: | | | | | | | | | | | | | | | | | |
Employee benefit trusts and investments(b) | 244 |
| | 49 |
| | — |
| | 17 |
| | 5 |
| | 130 |
| | 105 |
| | — |
| | — |
|
| Equity investments without readily determinable fair values | 72 |
| | 72 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other available for sale debt security investments | 40 |
| | 40 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total investments | $ | 625 |
|
| $ | 414 |
|
| $ | 6 |
|
| $ | 25 |
|
| $ | 5 |
|
| $ | 130 |
|
| $ | 105 |
|
| $ | — |
|
| $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2017 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Investments | | | | | | | | | | | | | | | | | |
| Equity method investments: | | | | | | | | | | | | | | | | | |
Financing trusts(a) | $ | 14 |
| | $ | — |
| | $ | 6 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Bloom | 206 |
| | 206 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| NET Power | 76 |
| | 76 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other equity method investments | 1 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total equity method investments | 297 |
|
| 283 |
|
| 6 |
|
| 8 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| Other investments: | | | | | | | | | | | | | | | | | |
Employee benefit trusts and investments(b) | 244 |
| | 51 |
| | — |
| | 17 |
| | 5 |
| | 132 |
| | 102 |
| | — |
| | — |
|
| Equity investments without readily determinable fair values | 62 |
| | 62 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other available for sale debt security investments | 37 |
| | 37 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total investments | $ | 640 |
|
| $ | 433 |
|
| $ | 6 |
|
| $ | 25 |
|
| $ | 5 |
|
| $ | 132 |
|
| $ | 102 |
|
| $ | — |
|
| $ | — |
|
__________
| |
(a) | Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments in the Consolidated Balance Sheets. See Note 1 — Significant Accounting Policies for additional information. |
| |
(b) | The Registrants’ debt and equity security investments are recorded at fair market value. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Related Party Transactions
The following table presents the service company costs allocated to the Registrants:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Operating and maintenance from affiliates | | Capitalized costs |
| | For the years ended December 31, | | For the years ended December 31, |
| | 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 |
| Exelon | | | | | | | | | | | | |
| BSC | | | | | | | | $ | 585 | | | $ | 516 | | | $ | 448 | |
| PHISCO | | | | | | | | 61 | | | 72 | | | 79 | |
| Generation | | | | | | | | | | | | |
| BSC | | $ | 552 | | | $ | 570 | | | $ | 652 | | | 54 | | | 66 | | | 67 | |
| ComEd | | | | | | | | | | | | |
| BSC | | 283 | | | 263 | | | 265 | | | 186 | | | 148 | | | 135 | |
| PECO | | | | | | | | | | | | |
| BSC | | 150 | | | 149 | | | 146 | | | 76 | | | 88 | | | 64 | |
| BGE | | | | | | | | | | | | |
| BSC | | 170 | | | 157 | | | 157 | | | 132 | | | 126 | | | 79 | |
| PHI | | | | | | | | | | | | |
| BSC | | 152 | | | 139 | | | 147 | | | 149 | | | 88 | | | 102 | |
| PHISCO | | 0 | | | 0 | | | 0 | | | 61 | | | 72 | | | 79 | |
| Pepco | | | | | | | | | | | | |
| BSC | | 85 | | | 85 | | | 89 | | | 55 | | | 38 | | | 40 | |
| PHISCO | | 120 | | | 124 | | | 137 | | | 27 | | | 33 | | | 32 | |
| DPL | | | | | | | | | | | | |
| BSC | | 54 | | | 52 | | | 51 | | | 51 | | | 25 | | | 28 | |
| PHISCO | | 97 | | | 100 | | | 111 | | | 18 | | | 20 | | | 25 | |
| ACE | | | | | | | | | | | | |
| BSC | | 45 | | | 42 | | | 42 | | | 40 | | | 19 | | | 20 | |
| PHISCO | | 87 | | | 90 | | | 98 | | | 16 | | | 19 | | | 21 | |
Current Receivables from/Payables to affiliates
The following tables provide additional information about liabilities of the Registrants at present current receivables from affiliates and current payables to affiliates:
December 31, 2018 and 2017.2020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Receivables from affiliates: | | |
| Payables to affiliates: | | Generation | | ComEd | | PECO | | BGE | | | | Pepco | | DPL | | ACE | | BSC | | PHISCO | | Other | | Total |
| Generation | | | | $ | 13 | | | $ | 0 | | | $ | 0 | | | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 72 | | | $ | 0 | | | $ | 22 | | | $ | 107 | |
| ComEd | | $ | 78 | | (a) | | | 0 | | | 0 | | | | | 0 | | | 0 | | | 0 | | | 59 | | | 0 | | | 9 | | | 146 | |
| PECO | | 17 | | | 1 | | | | | 0 | | | | | 0 | | | 0 | | | 0 | | | 28 | | | 0 | | | 4 | | | 50 | |
| BGE | | 11 | | | 0 | | | 0 | | | | | | | 0 | | | 0 | | | 0 | | | 47 | | | — | | | 3 | | | 61 | |
| PHI | | 0 | | | 0 | | | 0 | | | 0 | | | | | 0 | | | 0 | | | 0 | | | 4 | | | 0 | | | 11 | | | 15 | |
| Pepco | | 13 | | | 2 | | | 0 | | | 1 | | | | | | | 0 | | | 0 | | | 25 | | | 14 | | | 0 | | | 55 | |
| DPL | | 3 | | | 1 | | | 0 | | | 0 | | | | | 0 | | | | | 0 | | | 21 | | | 10 | | | 1 | | | 36 | |
| ACE | | 6 | | | 0 | | | 0 | | | 0 | | | | | 0 | | | 0 | | | | | 15 | | | 9 | | | 1 | | | 31 | |
| Other | | 25 | | | 5 | | | 2 | | | 2 | | | | | 2 | | | 1 | | | 6 | | | 0 | | | 0 | | | | | 43 | |
| Total | | $ | 153 | | | $ | 22 | | | $ | 2 | | | $ | 3 | | | | | $ | 2 | | | $ | 1 | | | $ | 6 | | | $ | 271 | | | $ | 33 | | | $ | 51 | | | $ | 544 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2018 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Accrued expenses | | | | | | | | | | | | | | |
Compensation-related accruals(a) | $ | 1,191 |
| | $ | 479 |
| | $ | 187 |
| | $ | 49 |
| | $ | 68 |
| | $ | 99 |
| | $ | 29 |
| | $ | 19 |
| | $ | 12 |
|
| Taxes accrued | 412 |
| | 226 |
| | 71 |
| | 28 |
| | 46 |
| | 74 |
| | 58 |
| | 4 |
| | 5 |
|
| Interest accrued | 334 |
| | 77 |
| | 105 |
| | 33 |
| | 39 |
| | 50 |
| | 25 |
| | 8 |
| | 12 |
|
| Severance accrued | 44 |
| | 26 |
| | 2 |
| | — |
| | — |
| | 5 |
| | — |
| | — |
| | — |
|
| Other accrued expenses | 131 |
| | 90 |
|
| 8 |
| | 3 |
| | 2 |
| | 28 |
| | 14 |
| | 8 |
| | 6 |
|
| Total accrued expenses | $ | 2,112 |
| | $ | 898 |
| | $ | 373 |
| | $ | 113 |
| | $ | 155 |
|
| $ | 256 |
|
| $ | 126 |
|
| $ | 39 |
|
| $ | 35 |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| December 31, 2017 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Accrued expenses | | | | | | | | | | | | | | |
Compensation-related accruals(a) | $ | 978 |
| | $ | 407 |
| | $ | 158 |
| | $ | 64 |
| | $ | 58 |
| | $ | 106 |
| | $ | 29 |
| | $ | 17 |
| | $ | 11 |
|
| Taxes accrued | 373 |
| | 444 |
| | 60 |
| | 15 |
| | 71 |
| | 61 |
| | 68 |
| | 4 |
| | 5 |
|
| Interest accrued | 328 |
| | 78 |
| | 102 |
| | 33 |
| | 34 |
| | 48 |
| | 23 |
| | 8 |
| | 12 |
|
| Severance accrued | 58 |
| | 30 |
| | 2 |
| | — |
| | — |
| | 17 |
| | — |
| | — |
| | — |
|
| Other accrued expenses | 100 |
| | 63 |
|
| 5 |
| | 2 |
| | 1 |
| | 29 |
| | 17 |
| | 6 |
| | 5 |
|
| Total accrued expenses | $ | 1,837 |
| | $ | 1,022 |
| | $ | 327 |
| | $ | 114 |
| | $ | 164 |
|
| $ | 261 |
|
| $ | 137 |
|
| $ | 35 |
|
| $ | 33 |
|
__________
| |
(a) | Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits. |
24. Segment Information (All Registrants)
Operating segments for eachTable of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to evaluate performance and allocate resources at each of the Registrants.
Exelon has twelve reportable segments, which include Generation's six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income.
The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of Generation’s six reportable segments are as follows:
Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.
Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
New England represents operations within ISO-NE.Note 25 — Related Party Transactions
New York represents operations within ISO-NY.
December 31, 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Receivables from affiliates: | | |
| Payables to affiliates: | | Generation | | ComEd | | PECO | | BGE | | | | | | | | ACE | | BSC | | PHISCO | | Other | | Total |
| Generation | | | | $ | 27 | | | $ | 0 | | | $ | 0 | | | | | | | | | $ | 0 | | | $ | 67 | | | $ | 0 | | | $ | 23 | | | $ | 117 | |
| ComEd | | $ | 78 | | (a) | | | 0 | | | 0 | | | | | | | | | 0 | | | 54 | | | 0 | | | 8 | | | 140 | |
| PECO | | 27 | | | 0 | | | | | 0 | | | | | | | | | 0 | | | 25 | | | 0 | | | 3 | | | 55 | |
| BGE | | 28 | | | 0 | | | 0 | | | | | | | | | | | 0 | | | 34 | | | 0 | | | 4 | | | 66 | |
| PHI | | 0 | | | 0 | | | 0 | | | 0 | | | | | | | | | 0 | | | 4 | | | 0 | | | 10 | | | 14 | |
| Pepco | | 34 | | | 0 | | | 0 | | | 0 | | | | | | | | | 0 | | | 16 | | | 15 | | | 1 | | | 66 | |
| DPL | | 7 | | | 0 | | | 0 | | | 0 | | | | | | | | | 3 | | | 10 | | | 11 | | | 1 | | | 32 | |
| ACE | | 7 | | | 0 | | | 0 | | | 0 | | | | | | | | | | | 7 | | | 10 | | | 1 | | | 25 | |
| Other | | 9 | | | 1 | | | 1 | | | 1 | | | | | | | | | 1 | | | 0 | | | 0 | | | | | 13 | |
| Total | | $ | 190 | | | $ | 28 | | | $ | 1 | | | $ | 1 | | | | | | | | | $ | 4 | | | $ | 217 | | | $ | 36 | | | $ | 51 | | | $ | 528 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
ERCOT represents operations within Electric Reliability Council__________
(a)At December 31, 2020 and 2019, Generation also had a contract liability with ComEd for $50 million and $37 million, respectively, that was included in Other liabilities on Generation’s Consolidated Balance Sheets. At December 31, 2020 and 2019, ComEd had a Current Payable to Generation of Texas.
$28 million and $41 million, respectively, on its Consolidated Balance Sheets, which consisted of Generation’s Current Receivable from ComEd, partially offset by Generation’s contract liability with ComEd.Other Power Regions:
Borrowings from Exelon/PHI intercompany money poolSouth represents operationsTo provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. Generation, ComEd, PECO, and PHI Corporate participate in the FRCC, MISO’s Southern Region,Exelon money pool. Pepco, DPL, and ACE participate in the remaining portionsPHI intercompany money pool.
Noncurrent Receivables from/Payables to affiliates
Generation has long-term payables to ComEd and PECO as a result of the SERC not included within MISO or PJM.
West represents operations innuclear decommissioning contractual construct whereby, to the WECC, including California ISO.
Canada represents operations acrossextent NDT funds are greater than the entire countryunderlying ARO at the end of Canadadecommissioning, such amounts are due back to ComEd and includes AESO, OIESO and the Canadian portion of MISO.
PECO, as applicable, for payment to their respective customers. See Note 10 — Asset Retirement Obligations for additional information.The CODMs for Exelonfollowing table presents noncurrent receivables from affiliates at ComEd and Generation evaluate the performancePECO which are recorded as noncurrent payables to affiliates at Generation:
| | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 |
| ComEd | $ | 2,541 | | | $ | 2,622 | |
| PECO | 475 | | | 480 | |
Long-term debt to financing trusts
The following table presents Long-term debt to financing trusts:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2020 | | 2019 |
| Exelon | | ComEd | | PECO | | Exelon | | ComEd | | PECO |
| ComEd Financing III | $ | 206 | | | $ | 205 | | | $ | 0 | | | $ | 206 | | | $ | 205 | | | $ | 0 | |
| PECO Trust III | 81 | | | 0 | | | 81 | | | 81 | | | 0 | | | 81 | |
| PECO Trust IV | 103 | | | 0 | | | 103 | | | 103 | | | 0 | | | 103 | |
| Total | $ | 390 | | | $ | 205 | | | $ | 184 | | | $ | 390 | | | $ | 205 | | | $ | 184 | |
Long-term debt to affiliates
During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation will disclose five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. Beginning in the first quarter of 2019, Other Power Regions will include:
South represents operations in the FRCC, MISO’s Southern Region, the remaining portions of the SERC not included within MISO or PJM.
West represents operations in the WECC, including California ISO.
Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.
New England represents operations within ISO-NE.
Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Related Party Transactions
An analysis and reconciliationIn connection with the debt obligations assumed by Exelon as part of the Registrants’ reportable segment information toConstellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the respective information interms and amounts of the consolidated financial statements for the years ended December 31, 2018, 2017, and 2016 is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Successor | | | | | | |
| Generation (a) |
| ComEd |
| PECO |
| BGE |
| PHI (e) | | Other (b) |
| Intersegment
Eliminations |
| Exelon |
Operating revenues(c): | | | | | | | | | | | | | | | |
| 2018 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 17,411 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1,256 | ) | | $ | 16,155 |
|
| Competitive businesses natural gas revenues | 2,718 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (8 | ) | | 2,710 |
|
| Competitive businesses other revenues | 308 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (5 | ) | | 303 |
|
| Rate-regulated electric revenues | — |
| | 5,882 |
| | 2,470 |
| | 2,428 |
| | 4,609 |
| | — |
| | (45 | ) | | 15,344 |
|
| Rate-regulated natural gas revenues | — |
| | — |
| | 568 |
| | 741 |
| | 181 |
| | — |
| | (20 | ) | | 1,470 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 15 |
| | 1,948 |
| | (1,960 | ) | | 3 |
|
| Total operating revenues | $ | 20,437 |
| | $ | 5,882 |
| | $ | 3,038 |
| | $ | 3,169 |
| | $ | 4,805 |
| | $ | 1,948 |
| | $ | (3,294 | ) | | $ | 35,985 |
|
| 2017 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 15,332 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1,105 | ) | | $ | 14,227 |
|
| Competitive businesses natural gas revenues | 2,575 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2,575 |
|
| Competitive businesses other revenues | 593 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | 592 |
|
| Rate-regulated electric revenues | — |
| | 5,536 |
| | 2,375 |
| | 2,489 |
| | 4,469 |
| | — |
| | (29 | ) | | 14,840 |
|
| Rate-regulated natural gas revenues | — |
| | — |
| | 495 |
| | 687 |
| | 161 |
| | — |
| | (10 | ) | | 1,333 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 49 |
| | 1,831 |
| | (1,880 | ) | | — |
|
| Total operating revenues | $ | 18,500 |
| | $ | 5,536 |
| | $ | 2,870 |
| | $ | 3,176 |
| | $ | 4,679 |
| | $ | 1,831 |
| | $ | (3,025 | ) | | $ | 33,567 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Successor | | | | | | |
| Generation (a) |
| ComEd |
| PECO |
| BGE |
| PHI (e) | | Other (b) |
| Intersegment
Eliminations |
| Exelon |
| 2016 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 15,400 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1,430 | ) | | $ | 13,970 |
|
| Competitive businesses natural gas revenues | 2,146 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2,146 |
|
| Competitive businesses other revenues | 211 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (4 | ) | | 207 |
|
| Rate-regulated electric revenues | — |
| | 5,254 |
| | 2,531 |
| | 2,609 |
| | 3,506 |
| | — |
| | (31 | ) | | 13,869 |
|
| Rate-regulated natural gas revenues | — |
| | — |
| | 463 |
| | 624 |
| | 92 |
| | — |
| | (13 | ) | | 1,166 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 45 |
| | 1,648 |
| | (1,686 | ) | | 7 |
|
| Total operating revenues | $ | 17,757 |
| | $ | 5,254 |
| | $ | 2,994 |
| | $ | 3,233 |
| | $ | 3,643 |
| | $ | 1,648 |
| | $ | (3,164 | ) | | $ | 31,365 |
|
| | | | | | | | | | | | | | | | |
Intersegment revenues(d): | | | | | | | | | | | | | | | |
| 2018 | $ | 1,269 |
| | $ | 27 |
| | $ | 8 |
| | $ | 29 |
| | $ | 15 |
| | $ | 1,942 |
| | $ | (3,289 | ) | | $ | 1 |
|
| 2017 | 1,110 |
| | 15 |
| | 7 |
| | 16 |
| | 50 |
| | 1,824 |
| | (3,020 | ) | | 2 |
|
| 2016 | 1,428 |
| | 15 |
| | 8 |
| | 21 |
| | 45 |
| | 1,647 |
| | (3,159 | ) | | 5 |
|
| Depreciation and amortization: | | | | | | | | | | | | | | | |
| 2018 | $ | 1,797 |
| | $ | 940 |
| | $ | 301 |
| | $ | 483 |
| | $ | 740 |
| | $ | 92 |
| | $ | — |
| | $ | 4,353 |
|
| 2017 | 1,457 |
| | 850 |
| | 286 |
| | 473 |
| | 675 |
| | 87 |
| | — |
| | 3,828 |
|
| 2016 | 1,879 |
| | 775 |
| | 270 |
| | 423 |
| | 515 |
| | 74 |
| | — |
| | 3,936 |
|
Operating expenses (c): | | | | | | | | | | | | | | | |
| 2018 | $ | 19,510 |
| | $ | 4,741 |
| | $ | 2,452 |
| | $ | 2,696 |
| | $ | 4,156 |
| | $ | 1,929 |
| | $ | (3,341 | ) | | $ | 32,143 |
|
| 2017 | 18,001 |
| | 4,214 |
| | 2,215 |
| | 2,562 |
| | 3,911 |
| | 1,742 |
| | (3,026 | ) | | 29,619 |
|
| 2016 | 16,878 |
| | 4,056 |
| | 2,292 |
| | 2,683 |
| | 3,549 |
| | 1,812 |
| | (3,164 | ) | | 28,106 |
|
| Interest expense, net: | | | | | | | | | | | | | | | |
| 2018 | $ | 432 |
| | $ | 347 |
| | $ | 129 |
| | $ | 106 |
| | $ | 261 |
| | $ | 279 |
| | $ | — |
| | $ | 1,554 |
|
| 2017 | 440 |
| | 361 |
| | 126 |
| | 105 |
| | 245 |
| | 283 |
| | — |
| | 1,560 |
|
| 2016 | 364 |
| | 461 |
| | 123 |
| | 103 |
| | 195 |
| | 290 |
| | — |
| | 1,536 |
|
| Income (loss) before income taxes: | | | | | | | | | | | | | | | |
| 2018 | $ | 365 |
| | $ | 832 |
| | $ | 466 |
| | $ | 387 |
| | $ | 432 |
| | $ | (249 | ) | | $ | (1 | ) | | $ | 2,232 |
|
| 2017 | 1,455 |
| | 984 |
| | 538 |
| | 525 |
| | 578 |
| | (296 | ) | | (2 | ) | | 3,782 |
|
| 2016 | 857 |
| | 679 |
| | 587 |
| | 468 |
| | (58 | ) | | (555 | ) | | (5 | ) | | 1,973 |
|
| Income taxes: | | | | | | | | | | | | | | | |
| 2018 | $ | (108 | ) | | $ | 168 |
| | $ | 6 |
| | $ | 74 |
| | $ | 35 |
| | $ | (55 | ) | | $ | — |
| | $ | 120 |
|
| 2017 | (1,376 | ) | | 417 |
| | 104 |
| | 218 |
| | 217 |
| | 294 |
| | — |
| | (126 | ) |
| 2016 | 282 |
| | 301 |
| | 149 |
| | 174 |
| | 3 |
| | (156 | ) | | — |
| | 753 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Successor | | | | | | |
| Generation (a) |
| ComEd |
| PECO |
| BGE |
| PHI (e) | | Other (b) |
| Intersegment
Eliminations |
| Exelon |
| Net income (loss): | | | | | | | | | | | | | | | |
| 2018 | $ | 443 |
| | $ | 664 |
| | $ | 460 |
| | $ | 313 |
| | $ | 398 |
| | $ | (193 | ) | | $ | (1 | ) | | $ | 2,084 |
|
| 2017 | 2,798 |
| | 567 |
| | 434 |
| | 307 |
| | 362 |
| | (590 | ) | | (2 | ) | | 3,876 |
|
| 2016 | 550 |
| | 378 |
| | 438 |
| | 294 |
| | (61 | ) | | (398 | ) | | (5 | ) | | 1,196 |
|
| Capital expenditures: | | | | | | | | | | | | | | | |
| 2018 | $ | 2,242 |
| | $ | 2,126 |
| | $ | 849 |
| | $ | 959 |
| | $ | 1,375 |
| | $ | 43 |
| | $ | — |
| | $ | 7,594 |
|
| 2017 | $ | 2,259 |
| | $ | 2,250 |
| | $ | 732 |
| | $ | 882 |
| | $ | 1,396 |
| | $ | 65 |
| | $ | — |
| | $ | 7,584 |
|
| 2016 | $ | 3,078 |
| | $ | 2,734 |
| | $ | 686 |
| | $ | 934 |
| | $ | 1,008 |
| | $ | 113 |
| | $ | — |
| | $ | 8,553 |
|
| Total assets: | | | | | | | | | | | | | | | |
| 2018 | $ | 47,556 |
| | $ | 31,213 |
| | $ | 10,642 |
| | $ | 9,716 |
| | $ | 21,984 |
| | $ | 8,355 |
| | $ | (9,800 | ) | | $ | 119,666 |
|
| 2017 | 48,457 |
| | 29,726 |
| | 10,170 |
| | 9,104 |
| | 21,247 |
| | 8,618 |
| | (10,552 | ) | | 116,770 |
|
__________
| |
(a) | See Note 25 — Related Party Transactions for additional information on intersegment revenues.
|
| |
(b) | Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities. |
| |
(c) | Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes. |
| |
(d) | Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory authoritative guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. |
| |
(e) | Amounts included represent activity for PHI's successor period, March 24, 2016 through December 31, 2018. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Successor and Predecessor PHI:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pepco | | DPL | | ACE | | Other(b) | | Intersegment
Eliminations | | PHI |
Operating revenues(a): | | | | | | | | | | | |
| December 31, 2018 - Successor | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 2,239 |
| | $ | 1,151 |
| | $ | 1,236 |
| | $ | — |
| | $ | (17 | ) | | $ | 4,609 |
|
| Rate-regulated natural gas revenues | — |
| | 181 |
| | — |
| | — |
| | — |
| | 181 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | 435 |
| | (420 | ) | | 15 |
|
| Total operating revenues | $ | 2,239 |
| | $ | 1,332 |
| | $ | 1,236 |
| | $ | 435 |
| | $ | (437 | ) | | $ | 4,805 |
|
| December 31, 2017 - Successor | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 2,158 |
| | $ | 1,139 |
| | $ | 1,186 |
| | $ | — |
| | $ | (14 | ) | | $ | 4,469 |
|
| Rate-regulated natural gas revenues | — |
| | 161 |
| | — |
| | — |
| | — |
| | 161 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | 52 |
| | (3 | ) | | 49 |
|
| Total operating revenues | $ | 2,158 |
| | $ | 1,300 |
| | $ | 1,186 |
| | $ | 52 |
| | $ | (17 | ) | | $ | 4,679 |
|
| March 24, 2016 to December 31, 2016 - Successor | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 1,675 |
| | $ | 850 |
| | $ | 989 |
| | $ | 5 |
| | $ | (13 | ) | | $ | 3,506 |
|
| Rate-regulated natural gas revenues | — |
| | 92 |
| | — |
| | — |
| | — |
| | 92 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | 45 |
| | — |
| | 45 |
|
| Total operating revenues | $ | 1,675 |
| | $ | 942 |
| | $ | 989 |
| | $ | 50 |
| | $ | (13 | ) | | $ | 3,643 |
|
| January 1, 2016 to March 23, 2016 - Predecessor | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 511 |
| | $ | 279 |
| | $ | 268 |
| | $ | 42 |
| | $ | (4 | ) | | $ | 1,096 |
|
| Rate-regulated natural gas revenues | — |
| | 56 |
| | — |
| | 1 |
| | — |
| | 57 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total operating revenues | $ | 511 |
| | $ | 335 |
| | $ | 268 |
| | $ | 43 |
| | $ | (4 | ) | | $ | 1,153 |
|
| | | | | | | | | | | | |
| Intersegment revenues: | | | | | | | | | | | |
| December 31, 2018 - Successor | $ | 6 |
| | $ | 8 |
| | $ | 3 |
| | $ | 435 |
| | $ | (437 | ) | | $ | 15 |
|
| December 31, 2017 - Successor | 6 |
| | 8 |
| | 2 |
| | 53 |
| | (19 | ) | | 50 |
|
| March 24, 2016 to December 31, 2016 - Successor | 4 |
| | 5 |
| | 2 |
| | 47 |
| | (13 | ) | | 45 |
|
| January 1, 2016 to March 23, 2016 - Predecessor | 1 |
| | 2 |
| | 1 |
| | — |
| | (4 | ) | | — |
|
| Depreciation and amortization: | | | | | | | | | | | |
| December 31, 2018 - Successor | $ | 385 |
| | $ | 182 |
| | $ | 136 |
| | $ | 37 |
| | $ | — |
| | $ | 740 |
|
| December 31, 2017 - Successor | 321 |
| | 167 |
| | 146 |
| | 42 |
| | (1 | ) | | $ | 675 |
|
| March 24, 2016 to December 31, 2016 - Successor | 224 |
| | 120 |
| | 128 |
| | 43 |
| | — |
| | $ | 515 |
|
| January 1, 2016 to March 23, 2016 - Predecessor | 71 |
| | 37 |
| | 37 |
| | 11 |
| | (4 | ) | | $ | 152 |
|
| Operating expenses: | | | | | | | | | | |
|
|
| December 31, 2018 - Successor | $ | 1,919 |
| | $ | 1,143 |
| | $ | 1,087 |
| | $ | 442 |
| | $ | (435 | ) | | $ | 4,156 |
|
| December 31, 2017 - Successor | 1,760 |
| | 1,071 |
| | 1,029 |
| | 68 |
| | (17 | ) | | $ | 3,911 |
|
| March 24, 2016 to December 31, 2016 - Successor | 1,577 |
| | 952 |
| | 1,000 |
| | 33 |
| | (13 | ) | | $ | 3,549 |
|
| January 1, 2016 to March 23, 2016 - Predecessor | 443 |
| | 284 |
| | 251 |
| | 73 |
| | (3 | ) | | $ | 1,048 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pepco | | DPL | | ACE | | Other(b) | | Intersegment
Eliminations | | PHI |
| Interest expense, net: | | | | | | | | | | |
|
|
| December 31, 2018 - Successor | $ | 128 |
| | $ | 58 |
| | $ | 64 |
| | $ | 11 |
| | $ | — |
| | $ | 261 |
|
| December 31, 2017 - Successor | 121 |
| | 51 |
| | 61 |
| | 13 |
| | (1 | ) | | $ | 245 |
|
| March 24, 2016 to December 31, 2016 - Successor | 98 |
| | 38 |
| | 47 |
| | 12 |
| | — |
| | $ | 195 |
|
| January 1, 2016 to March 23, 2016 - Predecessor | 29 |
| | 12 |
| | 15 |
| | 11 |
| | (2 | ) | | $ | 65 |
|
| Income (loss) before income taxes: | | | | | | | | | | |
|
|
| December 31, 2018 - Successor | $ | 223 |
| | $ | 142 |
| | $ | 87 |
| | $ | 388 |
| | $ | (408 | ) | | $ | 432 |
|
| December 31, 2017 - Successor | 310 |
| | 192 |
| | 103 |
| | 377 |
| | (404 | ) | | $ | 578 |
|
| March 24, 2016 to December 31, 2016 - Successor | 36 |
| | (30 | ) | | (51 | ) | | (84 | ) | | 71 |
| | $ | (58 | ) |
| January 1, 2016 to March 23, 2016 - Predecessor | 47 |
| | 43 |
| | 5 |
| | 59 |
| | (118 | ) | | $ | 36 |
|
| Income taxes: | | | | | | | | | | |
|
|
| December 31, 2018 - Successor | $ | 13 |
| | $ | 22 |
| | $ | 12 |
| | $ | (10 | ) | | $ | (2 | ) | | $ | 35 |
|
| December 31, 2017 - Successor | 105 |
| | 71 |
| | 26 |
| | 15 |
| | — |
| | $ | 217 |
|
| March 24, 2016 to December 31, 2016 - Successor | 26 |
| | 5 |
| | (5 | ) | | (23 | ) | | — |
| | $ | 3 |
|
| January 1, 2016 to March 23, 2016 - Predecessor | 15 |
| | 17 |
| | 1 |
| | (16 | ) | | — |
| | $ | 17 |
|
| Net income (loss): | | | | | | | | | | |
|
|
| December 31, 2018 - Successor | $ | 210 |
| | $ | 120 |
| | $ | 75 |
| | $ | (22 | ) | | $ | 15 |
| | $ | 398 |
|
| December 31, 2017 - Successor | 205 |
| | 121 |
| | 77 |
| | (91 | ) | | 50 |
| | $ | 362 |
|
| March 24, 2016 to December 31, 2016 - Successor | 10 |
| | (35 | ) | | (47 | ) | | (34 | ) | | 45 |
| | $ | (61 | ) |
| January 1, 2016 to March 23, 2016 - Predecessor | 32 |
| | 26 |
| | 5 |
| | (44 | ) | | — |
| | $ | 19 |
|
| Capital expenditures: | | | | | | | | | | |
|
|
| December 31, 2018 - Successor | $ | 656 |
| | $ | 364 |
| | $ | 335 |
| | $ | 20 |
| | $ | — |
| | $ | 1,375 |
|
| December 31, 2017 - Successor | 628 |
| | 428 |
| | 312 |
| | 28 |
| | — |
| | $ | 1,396 |
|
| March 24, 2016 to December 31, 2016 - Successor | 489 |
| | 277 |
| | 218 |
| | 24 |
| | — |
| | 1,008 |
|
| January 1, 2016 to March 23, 2016 - Predecessor | 97 |
| | 72 |
| | 93 |
| | 11 |
| | — |
| | 273 |
|
| Total assets: | | | | | | | | | | | |
| December 31, 2018 - Successor | $ | 8,299 |
| | $ | 4,588 |
| | $ | 3,699 |
| | $ | 10,819 |
| | $ | (5,421 | ) | | $ | 21,984 |
|
| December 31, 2017 - Successor | 7,832 |
| | 4,357 |
| | 3,445 |
| | 10,600 |
| | (4,987 | ) | | 21,247 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
__________
| |
(a) | Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes. |
| |
(b) | Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor periods presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger. |
The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation's two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon's disaggregated revenues are consistent with Generation and the Utility Registrants but exclude any intercompany revenues.
Competitive Business Revenues (Generation):
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 |
| | Revenues from external customers(a) | | | | |
| | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues |
| Mid-Atlantic | $ | 5,241 |
|
| $ | 233 |
| | $ | 5,474 |
| | $ | 13 |
|
| $ | 5,487 |
|
| Midwest | 4,527 |
|
| 190 |
| | 4,717 |
| | (11 | ) |
| 4,706 |
|
| New England | 2,660 |
|
| 185 |
| | 2,845 |
| | (4 | ) |
| 2,841 |
|
| New York | 1,723 |
|
| (36 | ) | | 1,687 |
| | — |
|
| 1,687 |
|
| ERCOT | 572 |
|
| 560 |
| | 1,132 |
| | 1 |
|
| 1,133 |
|
| Other Power Regions | 870 |
|
| 686 |
| | 1,556 |
| | (62 | ) |
| 1,494 |
|
| Total Competitive Businesses Electric Revenues | 15,593 |
|
| 1,818 |
| | 17,411 |
| | (63 | ) |
| 17,348 |
|
| Competitive Businesses Natural Gas Revenues | 1,524 |
|
| 1,194 |
| | 2,718 |
| | 62 |
|
| 2,780 |
|
Competitive Businesses Other Revenues(c) | 510 |
| | (202 | ) | | 308 |
| | 1 |
| | 309 |
|
| Total Generation Consolidated Operating Revenues | 17,627 |
|
| 2,810 |
| | $ | 20,437 |
| | $ | — |
|
| $ | 20,437 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | |
| | 2017 |
| | Revenues from external customers(a) | | | | |
| | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues |
| Mid-Atlantic | $ | 5,523 |
| | $ | (8 | ) | | $ | 5,515 |
| | $ | 25 |
| | $ | 5,540 |
|
| Midwest | 3,923 |
| | 283 |
| | 4,206 |
| | (25 | ) | | 4,181 |
|
| New England | 2,064 |
| | (54 | ) | | 2,010 |
| | (8 | ) | | 2,002 |
|
| New York | 1,605 |
| | (38 | ) | | 1,567 |
| | (17 | ) | | 1,550 |
|
| ERCOT | 641 |
| | 317 |
| | 958 |
| | 4 |
| | 962 |
|
| Other Power Regions | 594 |
| | 482 |
| | 1,076 |
| | (27 | ) | | 1,049 |
|
| Total Competitive Businesses Electric Revenues | 14,350 |
| | 982 |
| | 15,332 |
| | (48 | ) | | 15,284 |
|
| Competitive Businesses Natural Gas Revenues | 1,658 |
| | 917 |
| | 2,575 |
| | 53 |
| | 2,628 |
|
Competitive Businesses Other Revenues(c) | 744 |
| | (151 | ) | | 593 |
| | (5 | ) | | 588 |
|
| Total Generation Consolidated Operating Revenues | $ | 16,752 |
| | $ | 1,748 |
| | $ | 18,500 |
| | $ | — |
| | $ | 18,500 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | 2016 |
| | Revenues from external customers(a) | | | | |
| | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues |
| Mid-Atlantic | $ | 6,182 |
| | $ | 30 |
| | $ | 6,212 |
| | $ | (33 | ) | | $ | 6,179 |
|
| Midwest | 4,007 |
| | 395 |
| | 4,402 |
| | 10 |
| | 4,412 |
|
| New England | 1,953 |
| | (175 | ) | | 1,778 |
| | (9 | ) | | 1,769 |
|
| New York | 1,198 |
| | 10 |
| | 1,208 |
| | (42 | ) | | 1,166 |
|
| ERCOT | 810 |
| | 21 |
| | 831 |
| | 6 |
| | 837 |
|
| Other Power Regions | 670 |
| | 299 |
| | 969 |
| | (62 | ) | | 907 |
|
| Total Competitive Businesses Electric Revenues | 14,820 |
| | 580 |
| | 15,400 |
| | (130 | ) | | 15,270 |
|
| Competitive Businesses Natural Gas Revenues | 1,953 |
| | 193 |
| | 2,146 |
| | 135 |
| | 2,281 |
|
Competitive Businesses Other Revenues(c) | 756 |
| | (545 | ) | | 211 |
| | (5 | ) | | 206 |
|
| Total Generation Consolidated Operating Revenues | $ | 17,529 |
| | $ | 228 |
| | $ | 17,757 |
| | $ | — |
| | $ | 17,757 |
|
__________
| |
(a) | Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants. |
| |
(b) | Includes revenues from derivatives and leases. |
| |
(c) | Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $38 million and $52 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value in 2017 and 2016, respectively, unrealized mark-to-market losses of $262 million, $131 million, and $500 million in 2018, 2017, and 2016, respectively, and elimination of intersegment revenues. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Revenues net of purchased power and fuel expense (Generation):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| | RNF from external
customers(a) | | Intersegment
RNF | | Total RNF | | RNF from external
customers(a) | | Intersegment RNF | | Total RNF | | RNF from external
customers(a) | | Intersegment
RNF | | Total RNF |
| Mid-Atlantic | $ | 3,022 |
|
| $ | 51 |
| | $ | 3,073 |
| | $ | 3,105 |
|
| $ | 109 |
| | $ | 3,214 |
| | $ | 3,282 |
|
| $ | 35 |
| | $ | 3,317 |
|
| Midwest | 3,112 |
|
| 23 |
| | 3,135 |
| | 2,810 |
|
| 10 |
| | 2,820 |
| | 2,969 |
|
| 2 |
| | 2,971 |
|
| New England | 368 |
|
| (14 | ) | | 354 |
| | 538 |
|
| (24 | ) | | 514 |
| | 467 |
|
| (29 | ) | | 438 |
|
| New York | 1,112 |
|
| 10 |
| | 1,122 |
| | 1,007 |
|
| 1 |
| | 1,008 |
| | 771 |
|
| (19 | ) | | 752 |
|
| ERCOT | 501 |
|
| (243 | ) | | 258 |
| | 575 |
|
| (243 | ) | | 332 |
| | 412 |
|
| (131 | ) | | 281 |
|
| Other Power Regions | 515 |
|
| (140 | ) | | 375 |
| | 476 |
|
| (171 | ) | | 305 |
| | 483 |
|
| (147 | ) | | 336 |
|
Total Revenues net of purchased power and fuel for Reportable Segments | $ | 8,630 |
|
| $ | (313 | ) | | $ | 8,317 |
| | $ | 8,511 |
|
| $ | (318 | ) | | $ | 8,193 |
| | $ | 8,384 |
|
| $ | (289 | ) | | $ | 8,095 |
|
Other (b) | 114 |
|
| 313 |
| | 427 |
| | 299 |
|
| 318 |
| | 617 |
| | 543 |
|
| 289 |
| | 832 |
|
Total Generation Revenues net of purchased power and fuel expense | $ | 8,744 |
|
| $ | — |
| | $ | 8,744 |
| | $ | 8,810 |
|
| $ | — |
| | $ | 8,810 |
| | $ | 8,927 |
|
| $ | — |
| | $ | 8,927 |
|
__________
| |
(a) | Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants. |
| |
(b) | Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $54 million and $57 million decrease in RNF for the amortization of intangible assets and liabilities related to commodity contracts in 2017 and 2016, respectively, unrealized mark-to-market losses of $319 million, $175 million, and $41 million in 2018, 2017, and 2016, respectively, accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 8 - Early Plant Retirements of $57 million, $12 million and $60 million for the year ended December 31, 2018, 2017, and 2016 and the elimination of intersegment RNF. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Electric and Gas Revenue by Customer Class (Utility Registrants):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 |
| | | | | | | | Successor | | | | | | |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 2,942 |
| | $ | 1,566 |
| | $ | 1,382 |
| | $ | 2,351 |
| | $ | 1,021 |
| | $ | 669 |
| | $ | 661 |
|
| Small commercial & industrial | 1,487 |
| | 404 |
| | 257 |
| | 488 |
| | 140 |
| | 186 |
| | 162 |
|
| Large commercial & industrial | 538 |
| | 223 |
| | 429 |
| | 1,124 |
| | 846 |
| | 100 |
| | 178 |
|
| Public authorities & electric railroads | 47 |
| | 28 |
| | 28 |
| | 58 |
| | 32 |
| | 14 |
| | 12 |
|
Other(a) | 867 |
| | 243 |
| | 327 |
| | 593 |
| | 193 |
| | 175 |
| | 227 |
|
Total rate-regulated electric revenues(b) | 5,881 |
| | 2,464 |
| | 2,423 |
| | 4,614 |
| | 2,232 |
| | 1,144 |
| | 1,240 |
|
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | — |
| | 395 |
| | 491 |
| | 99 |
| | — |
| | 99 |
| | — |
|
| Small commercial & industrial | — |
| | 143 |
| | 77 |
| | 44 |
| | — |
| | 44 |
| | — |
|
| Large commercial & industrial | — |
| | 1 |
| | 124 |
| | 8 |
| | — |
| | 8 |
| | — |
|
| Transportation | — |
| | 23 |
| | — |
| | 16 |
| | — |
| | 16 |
| | — |
|
Other(c) | — |
| | 6 |
| | 63 |
| | 13 |
| | — |
| | 13 |
| | — |
|
Total rate-regulated natural gas revenues(d) | — |
| | 568 |
| | 755 |
| | 180 |
| | — |
| | 180 |
| | — |
|
| Total rate-regulated revenues from contracts with customers | 5,881 |
| | 3,032 |
| | 3,178 |
| | 4,794 |
| | 2,232 |
| | 1,324 |
| | 1,240 |
|
| | | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | (29 | ) | | (7 | ) | | (26 | ) | | — |
| | — |
| | 4 |
| | (4 | ) |
Other rate-regulated electric revenues(e) | 30 |
| | 12 |
| | 13 |
| | 10 |
| | 7 |
| | 3 |
| | — |
|
Other rate-regulated natural gas revenues(e) | — |
| | 1 |
| | 4 |
| | 1 |
| | — |
| | 1 |
| | — |
|
| Total other revenues | 1 |
| | 6 |
| | (9 | ) | | 11 |
| | 7 |
| | 8 |
| | (4 | ) |
| Total rate-regulated revenues for reportable segments | $ | 5,882 |
| | $ | 3,038 |
| | $ | 3,169 |
| | $ | 4,805 |
| | $ | 2,239 |
| | $ | 1,332 |
| | $ | 1,236 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2017 |
| | | | | | | | Successor | | | | | | |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 2,715 |
| | $ | 1,505 |
| | $ | 1,365 |
| | $ | 2,246 |
| | $ | 964 |
| | $ | 663 |
| | $ | 619 |
|
| Small commercial & industrial | 1,363 |
| | 401 |
| | 254 |
| | 490 |
| | 137 |
| | 187 |
| | 166 |
|
| Large commercial & industrial | 455 |
| | 223 |
| | 427 |
| | 1,086 |
| | 794 |
| | 103 |
| | 189 |
|
| Public authorities & electric railroads | 44 |
| | 30 |
| | 31 |
| | 60 |
| | 33 |
| | 14 |
| | 13 |
|
Other(a) | 886 |
| | 204 |
| | 299 |
| | 541 |
| | 199 |
| | 163 |
| | 191 |
|
Total rate-regulated electric revenues(b) | 5,463 |
| | 2,363 |
| | 2,376 |
| | 4,423 |
| | 2,127 |
| | 1,130 |
| | 1,178 |
|
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | — |
| | 331 |
| | 437 |
| | 90 |
| | — |
| | 90 |
| | — |
|
| Small commercial & industrial | — |
| | 131 |
| | 75 |
| | 38 |
| | — |
| | 38 |
| | — |
|
| Large commercial & industrial | — |
| | 1 |
| | 119 |
| | 8 |
| | — |
| | 8 |
| | — |
|
| Transportation | — |
| | 23 |
| | — |
| | 15 |
| | — |
| | 15 |
| | — |
|
Other(c) | — |
| | 8 |
| | 28 |
| | 9 |
| | — |
| | 9 |
| | — |
|
Total rate-regulated natural gas revenues(d) | — |
| | 494 |
| | 659 |
| | 160 |
| | — |
| | 160 |
| | — |
|
| Total rate-regulated revenues from contracts with customers | 5,463 |
| | 2,857 |
| | 3,035 |
| | 4,583 |
| | 2,127 |
| | 1,290 |
| | 1,178 |
|
| | | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | 43 |
| | — |
| | 124 |
| | 40 |
| | 26 |
| | 6 |
| | 8 |
|
Other rate-regulated electric revenues(e) | 30 |
| | 12 |
| | 13 |
| | 8 |
| | 5 |
| | 3 |
| | — |
|
Other rate-regulated natural gas revenues(e) | — |
| | 1 |
| | 4 |
| | 1 |
| | — |
| | 1 |
| | — |
|
Other revenues(f) | — |
| | — |
| | — |
| | 47 |
| | — |
| | — |
| | — |
|
| Total other revenues | 73 |
| | 13 |
| | 141 |
| | 96 |
| | 31 |
| | 10 |
| | 8 |
|
| Total rate-regulated revenues for reportable segments | $ | 5,536 |
| | $ | 2,870 |
| | $ | 3,176 |
| | $ | 4,679 |
| | $ | 2,158 |
| | $ | 1,300 |
| | $ | 1,186 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | Successor | | | Predecessor |
| | 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
| Rate-regulated electric revenues | | | | | | | | | | | | | | | | |
| Residential | $ | 2,603 |
| | $ | 1,631 |
| | $ | 1,504 |
| | $ | 1,004 |
| | $ | 672 |
| | $ | 664 |
| | $ | 1,779 |
| | | $ | 561 |
|
| Small commercial & industrial | 1,318 |
| | 430 |
| | 276 |
| | 150 |
| | 188 |
| | 183 |
| | 400 |
| | | 121 |
|
| Large commercial & industrial | 462 |
| | 234 |
| | 434 |
| | 790 |
| | 99 |
| | 201 |
| | 835 |
| | | 255 |
|
| Public authorities & electric railroads | 45 |
| | 32 |
| | 35 |
| | 32 |
| | 13 |
| | 13 |
| | 45 |
| | | 13 |
|
Other(a) | 820 |
| | 192 |
| | 276 |
| | 190 |
| | 160 |
| | 187 |
| | 400 |
| | | 169 |
|
Total rate-regulated electric revenues(b) | 5,248 |
| | 2,519 |
| | 2,525 |
| | 2,166 |
| | 1,132 |
| | 1,248 |
| | 3,459 |
| | | 1,119 |
|
| Rate-regulated natural gas revenues | | | | | | | | | | | | | | | | |
| Residential | — |
| | 309 |
| | 432 |
| | — |
| | 86 |
| | — |
| | 50 |
| | | 36 |
|
| Small commercial & industrial | — |
| | 121 |
| | 66 |
| | — |
| | 35 |
| | — |
| | 21 |
| | | 14 |
|
| Large commercial & industrial | — |
| | — |
| | 114 |
| | — |
| | 6 |
| | — |
| | 4 |
| | | 2 |
|
| Transportation | — |
| | 24 |
| | — |
| | — |
| | 13 |
| | — |
| | 10 |
| | | 3 |
|
Other(c) | — |
| | 9 |
| | 28 |
| | — |
| | 8 |
| | — |
| | 7 |
| | | 2 |
|
Total rate-regulated natural gas revenues(d) | — |
| | 463 |
| | 640 |
| | — |
| | 148 |
| | — |
| | 92 |
| | | 57 |
|
| Total rate-regulated revenues from contracts with customers | 5,248 |
| | 2,982 |
| | 3,165 |
| | 2,166 |
| | 1,280 |
| | 1,248 |
| | 3,551 |
| | | 1,176 |
|
| | | | | | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | (24 | ) | | — |
| | 53 |
| | 14 |
| | (6 | ) | | 9 |
| | 43 |
| | | (26 | ) |
Other rate-regulated electric revenues(e) | 30 |
| | 12 |
| | 13 |
| | 6 |
| | 3 |
| | — |
| | 6 |
| | | 3 |
|
Other rate-regulated natural gas revenues(e) | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Other revenues(f) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 43 |
| | | — |
|
| Total other revenues | 6 |
| | 12 |
| | 68 |
| | 20 |
| | (3 | ) | | 9 |
| | 92 |
| | | (23 | ) |
| Total rate-regulated revenues for reportable segments | $ | 5,254 |
| | $ | 2,994 |
| | $ | 3,233 |
| | $ | 2,186 |
| | $ | 1,277 |
| | $ | 1,257 |
| | $ | 3,643 |
| | | $ | 1,153 |
|
__________
| |
(a) | Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue. |
| |
(b) | Includes operating revenues from affiliates of $27 million, $7 million, $8 million, $15 million, $6 million, $8 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018, $15 million, $6 million, $5 million, $3 million, $6 million, $8 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, in 2017, and $15 million, $7 million, $7 million, $2 million, $5 million, $7 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2016. |
| |
(c) | Includes revenues from off-system natural gas sales. |
| |
(d) | Includes operating revenues from affiliates of $1 million and $21 million at PECO and BGE, respectively, in 2018, $1 million and $11 million at PECO and BGE, respectively, in 2017, and $1 million and $14 million at PECO and BGE, respectively, in 2016. |
| |
(e) | Includes late payment charge revenues. |
| |
(f) | Includes operating revenues from affiliates of $47 million and $43 million at PHI in 2017 and 2016, respectively. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
25. Related Party Transactions (All Registrants)
Exelon
The financial statementsthird-party debt obligations of Exelon, include related party transactions as presentedresulting in the tables below:intercompany notes payable included in Long-term debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate.
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Operating revenues from affiliates: | | | | | |
Generation (a) | (2 | ) | | — |
| |
|
|
PECO (a) | — |
|
| 1 |
|
| 1 |
|
BGE (a) | — |
|
| 4 |
|
| 4 |
|
ACE (a) | — |
| | — |
| | — |
|
| Other | 1 |
| | 2 |
| | 5 |
|
| Total operating revenues from affiliates | $ | (1 | ) | | $ | 7 |
| | $ | 10 |
|
| Interest expense to affiliates, net: | | | | | |
| ComEd Financing III | $ | 13 |
| | $ | 14 |
| | $ | 13 |
|
| PECO Trust III | 6 |
| | 6 |
| | 6 |
|
| PECO Trust IV | 6 |
| | 6 |
| | 6 |
|
| BGE Capital Trust II | — |
| | 10 |
| | 16 |
|
| Total interest expense to affiliates, net | $ | 25 |
| | $ | 36 |
| | $ | 41 |
|
| Earnings (losses) in equity method investments: | | | | | |
| Qualifying facilities and domestic power projects | $ | (29 | ) | | $ | (33 | ) | | $ | (25 | ) |
| Other | 1 |
| | 1 |
| | 1 |
|
| Total losses in equity method investments | $ | (28 | ) | | $ | (32 | ) | | $ | (24 | ) |
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| Payables to affiliates (current): | | | |
| ComEd Financing III | $ | 4 |
| | $ | 4 |
|
| PECO Trust III | 1 |
| | 1 |
|
| Total payables to affiliates (current) | $ | 5 |
| | $ | 5 |
|
| Long-term debt to financing trusts: | | | |
| ComEd Financing III | $ | 206 |
| | $ | 205 |
|
| PECO Trust III | 81 |
| | 81 |
|
| PECO Trust IV | 103 |
| | 103 |
|
| Total long-term debt to financing trusts | $ | 390 |
| | $ | 389 |
|
__________
| |
(a) | The intersegment profit associated with the sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory authoritative guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations. See Note 4—Regulatory Matters for additional information. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Transactions involving Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE are further described in the tables below.
Generation
The financial statements of Generation include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Operating revenues from affiliates: | | | | | |
ComEd (a) | $ | 523 |
|
| $ | 121 |
|
| $ | 47 |
|
PECO (b) | 128 |
|
| 138 |
|
| 290 |
|
BGE (c) | 260 |
|
| 388 |
|
| 608 |
|
Pepco (d) | 206 |
| | 255 |
| | 295 |
|
DPL (e) | 120 |
| | 179 |
| | 154 |
|
ACE (f) | 29 |
| | 29 |
| | 37 |
|
| BSC | 2 |
|
| 1 |
|
| 2 |
|
| Other | — |
| | 4 |
| | 6 |
|
| Total operating revenues from affiliates | $ | 1,268 |
| | $ | 1,115 |
| | $ | 1,439 |
|
| Purchased power and fuel from affiliates: | | | | | |
| ComEd | $ | (6 | ) | | $ | 13 |
| | $ | — |
|
| BGE | 20 |
| | 9 |
| | 12 |
|
| Other | — |
| | (3 | ) | | — |
|
| Total purchased power and fuel from affiliates | $ | 14 |
| | $ | 19 |
| | $ | 12 |
|
| Operating and maintenance from affiliates: | | | | | |
ComEd (g) | $ | 7 |
| | $ | 7 |
| | $ | 7 |
|
PECO (g) | 2 |
| | 1 |
| | 3 |
|
BGE (g) | 2 |
| | 1 |
| | 1 |
|
| Pepco | 1 |
| | — |
| | 1 |
|
| PHISCO | 1 |
| | 1 |
| | 1 |
|
BSC (h) | 652 |
| | 689 |
| | 650 |
|
| Other | (4 | ) | | (2 | ) | | — |
|
| Total operating and maintenance from affiliates | $ | 661 |
| | $ | 697 |
| | $ | 663 |
|
| Interest expense to affiliates, net: | | | | | |
Exelon Corporate (i) | $ | 36 |
| | $ | 37 |
| | $ | 39 |
|
| PCI | — |
| | 1 |
| | — |
|
| PECO | — |
| | 1 |
| | — |
|
| Total interest expense to affiliates, net: | $ | 36 |
| | $ | 39 |
| | $ | 39 |
|
| Earnings (losses) in equity method investments | | | | | |
| Qualifying facilities and domestic power projects | $ | (30 | ) | | $ | (33 | ) | | $ | (25 | ) |
| Capitalized costs | | | | | |
BSC (h) | $ | 67 |
| | $ | 98 |
| | $ | 98 |
|
| Cash distributions paid to member | $ | 1,001 |
| | $ | 659 |
| | $ | 922 |
|
| Contributions from member | $ | 155 |
| | $ | 102 |
| | $ | 142 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| Receivables from affiliates (current): | | | |
ComEd (a) | $ | 69 |
| | $ | 28 |
|
PECO (b) | 30 |
| | 26 |
|
BGE (c) | 24 |
| | 24 |
|
Pepco (d) | 28 |
| | 36 |
|
DPL (e) | 7 |
| | 12 |
|
ACE (f) | 5 |
| | 6 |
|
PHISCO (h) | — |
| | 1 |
|
| Other | 10 |
| | 7 |
|
| Total receivables from affiliates (current) | $ | 173 |
| | $ | 140 |
|
| Intercompany money pool (current): | | | |
| Exelon Corporate | $ | 100 |
| | $ | — |
|
| PCI | — |
| | 54 |
|
| Total intercompany money pool (current) | $ | 100 |
| | $ | 54 |
|
| Payables to affiliates (current): | | | |
Exelon Corporate (i) | $ | 17 |
| | $ | 21 |
|
BSC (h) | 95 |
| | 74 |
|
| ComEd | 19 |
| | 12 |
|
PECO (b) | — |
| | 4 |
|
| Other | 8 |
| | 12 |
|
| Total payables to affiliates (current) | $ | 139 |
| | $ | 123 |
|
| Other liabilities to affiliates (current): | | | |
ComEd (a) | $ | 14 |
| | $ | — |
|
| Long-term debt to affiliates (noncurrent): | | | |
Exelon Corporate (k) | $ | 898 |
| | $ | 910 |
|
| Payables to affiliates (noncurrent): | | | |
ComEd (j) | $ | 2,217 |
| | $ | 2,528 |
|
PECO (j) | 389 |
| | 537 |
|
| Total payables to affiliates (noncurrent) | $ | 2,606 |
| | $ | 3,065 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
__________
| |
(a) | Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd. |
| |
(b) | Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs. |
| |
(c) | Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. |
| |
(d) | Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. |
| |
(e) | Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs. |
| |
(f) | Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process. |
| |
(g) | Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and BGE and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations. |
| |
(h) | Generation receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(i) | The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation. |
| |
(j) | Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15—Asset Retirement Obligations for additional information. |
| |
(k) | In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term Debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation in Exelon’s Consolidated Balance Sheets. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd
The financial statements of ComEd include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Operating revenues from affiliates | | | | | |
| Generation | $ | 9 |
|
| $ | 9 |
|
| $ | 7 |
|
BSC | 7 |
| | 6 |
| | 6 |
|
| PECO | 10 |
| | — |
| | 1 |
|
| BGE | 1 |
| | — |
| | 1 |
|
| Total operating revenues from affiliates | $ | 27 |
| | $ | 15 |
| | $ | 15 |
|
| Purchased power from affiliates | | | | | |
Generation (a) | $ | 529 |
| | $ | 108 |
| | $ | 47 |
|
| Operating and maintenance from affiliates | | | | | |
BSC (b) | $ | 265 |
| | $ | 270 |
| | $ | 225 |
|
| PECO | 1 |
| | — |
| | 1 |
|
| BGE | 1 |
| | — |
| | 1 |
|
| Total operating and maintenance from affiliates | $ | 267 |
| | $ | 270 |
| | $ | 227 |
|
| Interest expense to affiliates, net: | | | | | |
| ComEd Financing III | $ | 13 |
| | $ | 13 |
| | $ | 13 |
|
| Capitalized costs | | | | | |
BSC (b) | $ | 135 |
| | $ | 118 |
| | $ | 112 |
|
| Cash dividends paid to parent | $ | 459 |
| | $ | 422 |
| | $ | 369 |
|
| Contributions from parent | $ | 500 |
| | $ | 651 |
| | $ | 315 |
|
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
Prepaid voluntary employee beneficiary association trust (c) | $ | 5 |
| | $ | 2 |
|
| Receivables from affiliates (current): | | | |
| Voluntary employee beneficiary association trust | $ | 1 |
| | $ | 1 |
|
| Generation | 19 |
| | 12 |
|
| Total receivables from affiliates (current) | $ | 20 |
| | $ | 13 |
|
| Receivables from affiliates (noncurrent): | | | |
Generation (d) | $ | 2,217 |
| | $ | 2,528 |
|
| Payables to affiliates (current): | | | |
Generation (a) | $ | 55 |
| | $ | 28 |
|
BSC (b) | 56 |
| | 39 |
|
| ComEd Financing III | 4 |
| | 4 |
|
| Exelon Corporate | 4 |
| | 3 |
|
| Total payables to affiliates (current) | $ | 119 |
| | $ | 74 |
|
| Long-term debt to ComEd financing trust: | | | |
| ComEd Financing III | $ | 205 |
| | $ | 205 |
|
__________
| |
(a) | ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs and ZECs from Generation. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(b) | ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(c) | The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets. |
| |
(d) | ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers. |
PECO
The financial statements of PECO include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Operating revenues from affiliates: | | | | | |
Generation (a) | $ | 2 |
|
| $ | 1 |
|
| $ | 3 |
|
| BSC | 3 |
| | 5 |
| | 3 |
|
| ComEd | 1 |
| | — |
| | 1 |
|
| BGE | 1 |
| | 1 |
| | 1 |
|
| ACE | 1 |
| | — |
| | — |
|
| Total operating revenues from affiliates | $ | 8 |
| | $ | 7 |
| | $ | 8 |
|
| Purchased power from affiliates | | | | | |
Generation (b) | $ | 126 |
| | $ | 135 |
| | $ | 287 |
|
| Operating and maintenance from affiliates: | | | | | |
BSC (c) | $ | 146 |
| | $ | 146 |
| | $ | 142 |
|
| Generation | 2 |
| | 2 |
| | 2 |
|
ComEd
| 7 |
| | — |
| | 1 |
|
| BGE | 1 |
| | 1 |
| | 1 |
|
| Total operating and maintenance from affiliates | $ | 156 |
| | $ | 149 |
| | $ | 146 |
|
| Interest expense to affiliates, net: | | | | | |
| PECO Trust III | $ | 6 |
| | $ | 6 |
| | $ | 6 |
|
| PECO Trust IV | 6 |
| | 6 |
| | 6 |
|
Exelon Corporate
| 2 |
| | — |
| | — |
|
| Generation | — |
| | (1 | ) | | — |
|
| Total interest expense to affiliates, net: | $ | 14 |
| | $ | 11 |
| | $ | 12 |
|
| Capitalized costs | | | | | |
BSC (c) | $ | 64 |
| | $ | 59 |
| | $ | 57 |
|
| Cash dividends paid to parent | $ | 306 |
| | $ | 288 |
| | $ | 277 |
|
| Contributions from parent | $ | 89 |
| | $ | 16 |
| | $ | 18 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
Prepaid voluntary employee beneficiary association trust (d) | $ | 1 |
| | $ | — |
|
| Receivables from affiliates (noncurrent): | | | |
Generation (e) | $ | 389 |
| | $ | 537 |
|
| Payables to affiliates (current): | | | |
Generation (b) | $ | 30 |
| | $ | 22 |
|
BSC (c) | 26 |
| | 29 |
|
| Exelon Corporate | 2 |
| | 1 |
|
| PECO Trust III | 1 |
| | 1 |
|
| Total payables to affiliates (current) | $ | 59 |
| | $ | 53 |
|
| Long-term debt to financing trusts: | | | |
| PECO Trust III | $ | 81 |
| | $ | 81 |
|
| PECO Trust IV | 103 |
| | 103 |
|
| Total long-term debt to financing trusts | $ | 184 |
| | $ | 184 |
|
__________
| |
(a) | PECO provides energy to Generation for Generation’s own use. |
| |
(b) | PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. |
| |
(c) | PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(d) | The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. |
| |
(e) | PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
BGE
The financial statements of BGE include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Operating revenues from affiliates: | | | | | |
Generation (a) | $ | 22 |
|
| $ | 10 |
|
| $ | 13 |
|
BSC | 5 |
| | 5 |
| | 6 |
|
| ComEd | 1 |
| | — |
| | 1 |
|
| PECO | 1 |
| | 1 |
| | 1 |
|
| Total operating revenues from affiliates | $ | 29 |
| | $ | 16 |
| | $ | 21 |
|
| Purchased power from affiliates | | | | | |
Generation (b) | $ | 257 |
| | $ | 384 |
| | $ | 604 |
|
| Operating and maintenance from affiliates: | | | | | |
BSC (c) | $ | 157 |
| | $ | 152 |
| | $ | 130 |
|
| Generation | 3 |
| | — |
| | — |
|
| ComEd | 1 |
| | — |
| | 1 |
|
| PECO | 1 |
| | 1 |
| | 1 |
|
| Total operating and maintenance from affiliates | $ | 162 |
| | $ | 153 |
| | $ | 132 |
|
| Interest expense to affiliates, net: | | | | | |
| BGE Capital Trust II | $ | — |
| | $ | 10 |
| | $ | 16 |
|
| Capitalized costs | | | | | |
BSC (c) | $ | 79 |
| | $ | 54 |
| | $ | 36 |
|
| Cash dividends paid to parent | $ | 209 |
| | $ | 198 |
| | $ | 179 |
|
| Contributions from parent | $ | 109 |
| | $ | 184 |
| | $ | 61 |
|
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| Receivables from affiliates (current): | | | |
| Other | $ | 1 |
| | $ | 1 |
|
| Payables to affiliates (current): | | | |
Generation (b) | $ | 24 |
| | $ | 24 |
|
BSC (c) | 38 |
| | 25 |
|
| Exelon Corporate | 2 |
| | 1 |
|
| Other | 1 |
| | 2 |
|
| Total payables to affiliates (current) | $ | 65 |
| | $ | 52 |
|
__________
| |
(a) | BGE provides energy to Generation for Generation’s own use.
|
| |
(b) | BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. |
| |
(c) | BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI
The financial statements of PHI include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| | Successor |
| | For the Year Ended December 31, | | For the Year Ended December 31, | | March 24, 2016 to December 31, |
| | 2018 | | 2017 | | 2016 |
| Operating revenues from affiliates: | | | | | |
| BSC | $ | 12 |
| | $ | 48 |
| | $ | 44 |
|
| PHISCO | 1 |
| | 2 |
| | — |
|
| Generation | 2 |
| | — |
| | 1 |
|
| Total operating revenues from affiliates | $ | 15 |
| | $ | 50 |
| | $ | 45 |
|
| Purchased power from affiliates | | | | | |
| Generation | $ | 355 |
| | $ | 463 |
| | $ | 486 |
|
| Operating and maintenance from affiliates: | | | | | |
BSC (a) | $ | 147 |
| | $ | 145 |
| | $ | 86 |
|
| Other | 5 |
| | 5 |
| | 3 |
|
| Total operating and maintenance from affiliates | $ | 152 |
| | $ | 150 |
| | $ | 89 |
|
| Earnings (losses) in equity method investments: | | | | | |
| Other | $ | 1 |
| | $ | — |
| | $ | — |
|
| Capitalized costs: | | | | | |
BSC (a) | $ | 102 |
| | $ | — |
| | $ | — |
|
PHISCO (a) | 79 |
| | — |
| | — |
|
| Total capitalized costs | $ | 181 |
| | $ | — |
| | $ | — |
|
| Cash dividends paid to parent | $ | 326 |
| | $ | 311 |
| | $ | 273 |
|
| Contributions from parent | $ | 385 |
| | $ | 758 |
| | $ | 1,251 |
|
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| Payables to affiliates (current): | | | |
| Generation | $ | 40 |
| | $ | 54 |
|
| BGE | — |
| | 1 |
|
BSC(a) | 41 |
| | 24 |
|
| Exelon Corporate | 6 |
| | 6 |
|
| Other | 7 |
| | 5 |
|
| Total payables to affiliates (current) | $ | 94 |
| | $ | 90 |
|
__________
| |
(a) | PHI receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pepco
The financial statements of Pepco include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Operating revenues from affiliates: | | | | | |
Generation (a) | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| BSC | 1 |
| | — |
| | — |
|
| PHISCO | 4 |
| | 6 |
| | 4 |
|
| Total operating revenues from affiliates | $ | 6 |
| | $ | 6 |
| | $ | 5 |
|
| Purchased power from affiliates | | | | | |
Generation (b) | $ | 206 |
| | $ | 255 |
| | $ | 295 |
|
| Operating and maintenance: | | | | | |
PHISCO (c), (e) | $ | — |
| | $ | 219 |
| | $ | 263 |
|
PES (d) | — |
| | 29 |
| | 39 |
|
| Total operating and maintenance | $ | — |
| | $ | 248 |
| | $ | 302 |
|
| Operating and maintenance from affiliates: | | | | | |
BSC (c) | $ | 89 |
| | $ | 53 |
| | $ | 31 |
|
PHISCO (c), (e) | 137 |
| | 5 |
| | 4 |
|
| Total operating and maintenance from affiliates | $ | 226 |
| | $ | 58 |
| | $ | 35 |
|
| Capitalized costs: | | | | | |
BSC (c) | $ | 40 |
| | $ | — |
| | $ | — |
|
PHISCO (c) | 32 |
| | — |
| | — |
|
| Total capitalized costs | $ | 72 |
| | $ | — |
| | $ | — |
|
| Cash dividends paid to parent | $ | 169 |
| | $ | 133 |
| | $ | 136 |
|
| Contributions from parent | $ | 166 |
| | $ | 161 |
| | $ | 187 |
|
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| Receivables from affiliates (current): | | | |
| DPL | $ | 1 |
| | $ | — |
|
| Payables to affiliates (current): | | | |
| Exelon Corporation | $ | 1 |
| | $ | — |
|
Generation (b) | 28 |
| | 36 |
|
BSC (c) | 19 |
| | 11 |
|
PHISCO (c) | 14 |
| | 27 |
|
| Total payables to affiliates (current) | $ | 62 |
| | $ | 74 |
|
__________
| |
(a) | Pepco provides energy to Generation for Generation’s own use.
|
| |
(b) | Pepco procures a portion of its electricity supply requirements from Generation under its MDPSC and DCPSC approved market based SOS commodity programs. |
| |
(c) | Pepco receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(d) | PES performed underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(e) | Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018. |
DPL
The financial statements of DPL include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Operating revenues from affiliates: | | | | | |
| BSC | $ | 1 |
| | $ | — |
| | $ | — |
|
| PHISCO | 4 |
| | 6 |
| | 5 |
|
| ComEd | 1 |
| | — |
| | — |
|
| ACE | 1 |
| | — |
| | — |
|
| Other | 1 |
| | 2 |
| | 2 |
|
| Total operating revenues from affiliates | $ | 8 |
| | $ | 8 |
| | $ | 7 |
|
| Purchased power from affiliates | | | | | |
Generation (a) | $ | 120 |
| | $ | 179 |
| | $ | 154 |
|
| Operating and maintenance: | | | | | |
PHISCO (b), (d) | $ | — |
| | $ | 165 |
| | $ | 194 |
|
PES (c) | — |
| | 9 |
| | 8 |
|
| Total operating and maintenance | $ | — |
| | $ | 174 |
| | $ | 202 |
|
| Operating and maintenance from affiliates: | | | | | |
BSC (b) | $ | 51 |
| | $ | 31 |
| | $ | 18 |
|
PHISCO (b), (d) | 111 |
| | — |
| | — |
|
| Other | — |
| | 1 |
| | 1 |
|
| Total operating and maintenance from affiliates | $ | 162 |
| | $ | 32 |
| | $ | 19 |
|
| Capitalized costs: | | | | | |
BSC (b)
| $ | 28 |
| | $ | — |
| | $ | — |
|
PHISCO (b)
| 25 |
| | — |
| | — |
|
| Total capitalized costs | $ | 53 |
| | $ | — |
| | $ | — |
|
| Cash dividends paid to parent | $ | 96 |
| | $ | 112 |
| | $ | 54 |
|
| Contributions from parent | $ | 150 |
| | $ | — |
| | $ | 152 |
|
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| Payables to affiliates (current): | | | |
| Exelon Corporate | $ | 1 |
| | $ | — |
|
Generation (a) | 7 |
| | 12 |
|
BSC (b) | 11 |
| | 7 |
|
PHISCO (b) | 12 |
| | 27 |
|
| Pepco | 1 |
| | — |
|
| ACE | 1 |
| | — |
|
| Total payables to affiliates (current) | $ | 33 |
| | $ | 46 |
|
__________
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(a) | DPL procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs. |
| |
(b) | DPL receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(c) | PES performed underground transmission construction services, including services that are treated as capital costs, for DPL. |
| |
(d) | Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018. |
ACE
The financial statements of ACE include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Operating revenues from affiliates: | | | | | |
| PHISCO | $ | 2 |
| | $ | 1 |
| | $ | 2 |
|
| Other | 1 |
| | 1 |
| | 1 |
|
| Total operating revenues from affiliates | $ | 3 |
| | $ | 2 |
| | $ | 3 |
|
| Purchased power from affiliates | | | | | |
Generation (a) | $ | 29 |
| | $ | 29 |
| | $ | 37 |
|
| Operating and maintenance: | | | | | |
PHISCO (b), (c) | $ | — |
| | $ | 135 |
| | $ | 155 |
|
| Operating and maintenance from affiliates: | | | | | |
BSC (b) | $ | 42 |
| | $ | 25 |
| | $ | 15 |
|
PHISCO (b), (c) | 98 |
| | — |
| | — |
|
| Other | 2 |
| | 3 |
| | 3 |
|
| Total operating and maintenance from affiliates | $ | 142 |
| | $ | 28 |
| | $ | 18 |
|
| Capitalized costs: | | | | | |
BSC (b)
| $ | 20 |
| | $ | — |
| | $ | — |
|
PHISCO (b)
| 21 |
| | — |
| | — |
|
| Total capitalized costs | $ | 41 |
| | $ | — |
| | $ | — |
|
| Cash dividends paid to parent | $ | 59 |
| | $ | 68 |
| | $ | 63 |
|
| Contributions from parent | $ | 67 |
| | $ | — |
| | $ | 139 |
|
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| Receivable from affiliate (current): | | | |
| DPL | $ | 1 |
| | $ | — |
|
| Payables to affiliates (current): | | | |
Generation (a) | $ | 5 |
| | $ | 6 |
|
BSC (b) | 8 |
| | 5 |
|
PHISCO (b) | 13 |
| | 18 |
|
| Other | 2 |
| | — |
|
| Total payables to affiliates (current) | $ | 28 |
|
| $ | 29 |
|
__________
| |
(a) | ACE purchases electric supply from Generation under contracts executed through its competitive procurement process. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(b) | ACE receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(c) | Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018. |
26. Quarterly Data (Unaudited) (All Registrants)
Exelon
The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Revenues | | Operating Income | | Net Income
Attributable to
Common Shareholders |
| | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
| Quarter ended: | | | | | | | | | | | |
| March 31 | $ | 9,693 |
| | $ | 8,747 |
| | $ | 1,101 |
| | $ | 1,308 |
| | $ | 585 |
| | $ | 990 |
|
| June 30 | 8,076 |
| | 7,665 |
| | 942 |
| | 300 |
| | 539 |
| | 95 |
|
| September 30 | 9,403 |
| | 8,768 |
| | 1,146 |
| | 1,499 |
| | 733 |
| | 823 |
|
| December 31 | 8,814 |
| | 8,384 |
| | 708 |
| | 1,288 |
| | 152 |
| | 1,880 |
|
|
| | | | | | | | | | | | | | | |
| | Net Income
per Basic Share | | Net Income
per Diluted Share |
| | 2018 | | 2017 | | 2018 | | 2017 |
| Quarter ended: | | | | | | | |
| March 31 | $ | 0.61 |
| | $ | 1.07 |
| | $ | 0.60 |
| | $ | 1.06 |
|
| June 30 | 0.56 |
| | 0.10 |
| | 0.56 |
| | 0.10 |
|
| September 30 | 0.76 |
| | 0.86 |
| | 0.76 |
| | 0.85 |
|
| December 31 | 0.16 |
| | 1.95 |
| | 0.16 |
| | 1.94 |
|
Generation
The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Revenues | | Operating Income (Loss) | | Net Income (Loss)
Attributable to
Membership Interest |
| | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
| Quarter ended: | | | | | | | | | | | |
| March 31 | $ | 5,512 |
| | $ | 4,878 |
| | $ | 347 |
| | $ | 373 |
| | $ | 136 |
| | $ | 418 |
|
| June 30 | 4,579 |
| | 4,216 |
| | 282 |
| | (427 | ) | | 178 |
| | (235 | ) |
| September 30 | 5,278 |
| | 4,750 |
| | 311 |
| | 497 |
| | 234 |
| | 304 |
|
| December 31 | 5,069 |
| | 4,657 |
| | 35 |
| | 504 |
| | (178 | ) | | 2,224 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd
The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Revenues | | Operating Income | | Net Income |
| | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
| Quarter ended: | | | | | | | | | | | |
| March 31 | $ | 1,512 |
| | $ | 1,298 |
| | $ | 292 |
| | $ | 314 |
| | $ | 165 |
| | $ | 141 |
|
| June 30 | 1,398 |
| | 1,357 |
| | 288 |
| | 319 |
| | 164 |
| | 118 |
|
| September 30 | 1,598 |
| | 1,571 |
| | 323 |
| | 404 |
| | 193 |
| | 189 |
|
| December 31 | 1,373 |
| | 1,309 |
| | 242 |
| | 286 |
| | 141 |
| | 120 |
|
PECO
The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Revenues | | Operating Income | | Net Income |
| | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
| Quarter ended: | | | | | | | | | | | |
| March 31 | $ | 866 |
| | $ | 796 |
| | $ | 142 |
| | $ | 192 |
| | $ | 113 |
| | $ | 127 |
|
| June 30 | 653 |
| | 630 |
| | 127 |
| | 137 |
| | 96 |
| | 88 |
|
| September 30 | 757 |
| | 715 |
| | 154 |
| | 169 |
| | 126 |
| | 112 |
|
| December 31 | 765 |
| | 729 |
| | 165 |
| | 157 |
| | 124 |
| | 107 |
|
BGE
The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Revenues | | Operating Income | | Net Income |
| | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
| Quarter ended: | | | | | | | | | | | |
| March 31 | $ | 977 |
| | $ | 951 |
| | $ | 177 |
| | $ | 228 |
| | $ | 128 |
| | $ | 125 |
|
| June 30 | 662 |
| | 674 |
| | 85 |
| | 98 |
| | 51 |
| | 45 |
|
| September 30 | 731 |
| | 738 |
| | 103 |
| | 124 |
| | 63 |
| | 62 |
|
| December 31 | 799 |
| | 813 |
| | 109 |
| | 163 |
| | 71 |
| | 76 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI
The data shown below includes all adjustments that PHI considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Revenues | | Operating Income | | Net Income Attributable to Membership Interest |
| | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
| Quarter ended: | | | | | | | | | | | |
| March 31 | $ | 1,251 |
| | $ | 1,175 |
| | $ | 126 |
| | $ | 180 |
| | $ | 65 |
| | $ | 140 |
|
| June 30 | 1,076 |
| | 1,074 |
| | 153 |
| | 148 |
| | 84 |
| | 66 |
|
| September 30 | 1,361 |
| | 1,310 |
| | 245 |
| | 285 |
| | 187 |
| | 153 |
|
| December 31 | 1,117 |
| | 1,121 |
| | 126 |
| | 159 |
| | 62 |
| | 4 |
|
Pepco
The data shown below includes all adjustments that Pepco considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Revenues | | Operating Income | | Net Income |
| | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
| Quarter ended: | | | | | | | | | | | |
| March 31 | $ | 557 |
| | $ | 530 |
| | $ | 56 |
| | $ | 79 |
| | $ | 31 |
| | $ | 58 |
|
| June 30 | 523 |
| | 514 |
| | 85 |
| | 84 |
| | 54 |
| | 43 |
|
| September 30 | 628 |
| | 604 |
| | 112 |
| | 149 |
| | 89 |
| | 87 |
|
| December 31 | 531 |
| | 510 |
| | 65 |
| | 87 |
| | 36 |
| | 17 |
|
DPL
The data shown below includes all adjustments that DPL considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Revenues | | Operating Income | | Net Income |
| | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
| Quarter ended: | | | | | | | | | | | |
| March 31 | $ | 384 |
| | $ | 362 |
| | $ | 49 |
| | $ | 78 |
| | $ | 31 |
| | $ | 57 |
|
| June 30 | 289 |
| | 282 |
| | 42 |
| | 41 |
| | 26 |
| | 19 |
|
| September 30 | 328 |
| | 327 |
| | 51 |
| | 59 |
| | 33 |
| | 31 |
|
| December 31 | 331 |
| | 330 |
| | 48 |
| | 52 |
| | 30 |
| | 14 |
|
ACE
The data shown below includes all adjustments that ACE considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Revenues | | Operating Income | | Net Income (Loss) |
| | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
| Quarter ended: | | | | | | | | | | | |
| March 31 | $ | 310 |
| | $ | 275 |
| | $ | 23 |
| | $ | 25 |
| | $ | 7 |
| | $ | 28 |
|
| June 30 | 265 |
| | 270 |
| | 25 |
| | 25 |
| | 8 |
| | 8 |
|
| September 30 | 406 |
| | 370 |
| | 84 |
| | 79 |
| | 61 |
| | 41 |
|
| December 31 | 254 |
| | 271 |
| | 14 |
| | 28 |
| | (1 | ) | | — |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
27. Subsequent Events (Exelon and Generation)
Generation’s Antelope Valley,Planned Separation
On February 21, 2021, Exelon’s Board of Directors approved a 242 MW solar facilityplan to separate the Utility Registrants and Generation, creating two publicly traded companies. Under the separation plan, Exelon shareholders will retain their current shares of Exelon stock and receive a pro-rata distribution of shares of the new company’s stock in Lancaster, CA, sells alla transaction that is expected to be tax-free to Exelon and its shareholders for U.S. federal income tax purposes. The actual number of shares to be distributed to Exelon shareholders will be determined prior to closing.
Exelon is targeting to complete the separation in the first quarter of 2022, subject to final approval by Exelon’s Board of Directors, a Form 10 registration statement being declared effective by the SEC, regulatory approvals, and satisfaction of other conditions. The transaction is subject to approval by the FERC, NRC, and NYPSC, and receipt of a private letter ruling from the IRS and tax opinion from Exelon’s tax advisors. There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its outputterms or timing.
Impacts of February 2021 Weather Events and Texas-based Generating Assets Outages
Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced periodic outages as a result of historically severe cold weather conditions. In addition, those weather conditions drove increased demand for service, limited the availability of natural gas to Pacific Gasfuel power plants, dramatically increased wholesale power prices, and Electric Company (PG&E) through a PPA. As of December 31, 2018, Generation had approximately $750 millionalso increased gas prices in certain regions. In response to the high demand and $510 million of net long-lived assets and nonrecourse debt outstanding, respectively, relatedsignificantly reduced total generation on the system, ERCOT implemented load reductions to Antelope Valley. The nonrecourse debt is guaranteed bymaintain the DOE Loan Programs Office. Neither the guarantor nor the lender have recourse against Exelon or Generation in the event of default.
On January 29, 2019, PG&E filed for protection under Chapter 11reliability of the U.S. Bankruptcy Code. PG&E’s bankruptcy createsgrid and required the use of an eventadministrative price cap of default$9,000 per megawatt hour during load shedding events.
Exelon and Generation estimate the impact to their Net income for Antelope Valley’s nonrecourse debt. As such, Antelope Valley is currently in discussions with the DOE Loan Programs Office,first quarter of 2021 arising from these market and the debt has not yet been accelerated. Given that the event of default did not occur until January 2019, the debt continuedweather conditions to be classified as non-current onapproximately $560 million to $710 million. The estimated impact includes favorable results in certain regions within Generation’s wholesale gas business. The ultimate impact to Exelon’s and Generation’s Consolidated Balance Sheetsconsolidated financial statements may be affected by a number of factors, including final settlement data, the impacts of customer and counterparty credit losses, any state sponsored solutions to address the financial challenges caused by the event, and litigation and contract disputes which may result.
Generation used a combination of commercial paper and letters of credit to manage collateral needs and has posted approximately $1.4 billion of collateral with ERCOT as of December 31, 2018,February 22, 2021. Generation continues to believe it has sufficient cash on hand and may be reclassified to current in 2019.
Generation has also assessed and determined that Antelope Valley’s long-lived assets are not impairedavailable capacity on its revolver, which was $2.4 billion as of December 31, 2018. Changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley. The impairment loss could be substantially all of the net long-lived assets if Antelope Valley was valued without the PPA. Generation is monitoring the bankruptcy proceedings for any changes in circumstances that would indicate the carrying amount of the net long-lived assets of Antelope Valley may not be recoverable.February 22, 2021, to meet its liquidity requirements.
Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,990 million and $830 million of additional net long-lived assets and nonrecourse debt outstanding, respectively, as of December 31, 2018. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation and includes Generation's interest in EGRP and other projects with non-controlling interests. EGR IV is currently not in default, however, an acceleration of Antelope Valley’s debt could impact EGR IV. The lenders do not have recourse against Exelon or Generation in the event of default by EGR IV. See Note 2 - Variable Interest Entities for additional details on EGRP and Note 13 — Debt and Credit Agreements for additional details on Generation's nonrecourse project financings.
|
| | | | |
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
All Registrants
None.
|
| | | | |
| ITEM 9A. | CONTROLS AND PROCEDURES |
All Registrants—Disclosure Controls and Procedures
During the fourth quarter of 2018,2020, each registrant’s management, including its principal executive officer and principal financial officer, evaluated the effectiveness of that registrant’s disclosure controls and procedures
related to the recording, processing, summarizing, and reporting of information in that registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each registrant to ensure that (a) information relating to that registrant, including its consolidated subsidiaries, that is required to be included in filings under the Securities Exchange Act of 1934, is accumulated and made known to that registrant’s management, including its principal executive officer and principal financial officer, by other employees of that registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of December 31, 2018,2020, the principal executive officer and principal financial officer of each registrant concluded that such registrant’s disclosure controls and procedures were effective to accomplish their objectives.
All Registrants—Changes in Internal Control Over Financial Reporting
Each registrant continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the fourth quarter of 20182020 that have materially affected, or are reasonably likely to materially affect, any of the registrant'sRegistrant's internal control over financial reporting.reporting, including no changes resulting from COVID-19. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Executive Overview for additional information on COVID-19.
All Registrants—Internal Control Over Financial Reporting
Management is required to assess and report on the effectiveness of its internal control over financial reporting as of December 31, 2018.2020. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 20182020 and, therefore, concluded that each registrant’s internal control over financial reporting was effective. Management’s Report on Internal Control Over Financial Reporting is included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
|
| | | | |
| ITEM 9B. | OTHER INFORMATION |
All Registrants
None.On February 22, 2021, ComEd adopted Amended and Restated Bylaws to amend the standard for independent directors.
PART III
Exelon Generation Company, LLC, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, all items in this section relating to Generation, PECO, BGE, PHI, Pepco, DPL, and ACE are not presented.
|
| | | | |
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE |
Executive Officers
The information required by ITEM 10.10 relating to executive officers is set forth above in ITEM 1. BUSINESS—Executive officers of the Registrants at February 8, 2019.24, 2021.
Directors, Director Nomination Process and Audit Committee
The information required under ITEM 10 concerning directors and nominees for election as directors at the annual meeting of shareholders (Item 401 of Regulation S-K), the director nomination process (Item 407(c)(3)), the audit committee (Item 407(d)(4) and (d)(5)), and the beneficial reporting compliance (Sec. 16(a)) is incorporated herein by reference to information to be contained in Exelon’s definitive 20192021 proxy statement (2019(2021 Exelon Proxy Statement) and the ComEd information statement (2019(2021 ComEd Information Statement) to be filed with the SEC on or before April 30, 20192021 pursuant to Regulation 14A or 14C, as applicable, under the Securities Exchange Act of 1934.
Code of Ethics
Exelon’s Code of Business Conduct is the code of ethics that applies to Exelon’s and ComEd’s Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website at www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Carter C. Culver, Senior Vice President and Deputy General Counsel, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.
If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, Exelon will disclose the nature of such amendment or waiver on Exelon’s website, www.exeloncorp.com, or in a report on Form 8-K.
|
| | | | |
| ITEM 11. | EXECUTIVE COMPENSATION |
The information required by this item will be set forth under Executive Compensation Data and Report of the Compensation Committee in the Exelon Proxy Statement for the 20192021 Annual Meeting of Shareholders or the ComEd 20192021 Information Statement, which are incorporated herein by reference.
|
| | | | |
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
The additional information required by this item will be set forth under Ownership of Exelon Stock in the 20192021 Exelon Proxy Statement or the ComEd 20192021 Information Statement and incorporated herein by reference.
Securities Authorized for Issuance under Exelon Equity Compensation Plans
| | | | [A] | | [B] | | [C] | | [A] | | [B] | | [C] |
| Plan Category | Number of securities to be issued upon exercise of outstanding Options, warrants and rights (Note 1) | | Weighted-average price of outstanding Options, warrants and rights (Note 2) | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column [B]) (Note 3) | Plan Category | Number of securities to
be issued upon
exercise of outstanding
Options, warrants and
rights (Note 1) | | Weighted-average
price of outstanding
Options, warrants
and rights (Note 2) | | Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in
column [A]) (Note 3) |
| Equity compensation plans approved by security holders | 10,401,300 |
| | $ | 23.77 |
| | 30,071,500 |
| Equity compensation plans approved by security holders | 7,130,386 | | | $ | 16.29 | | | 46,987,104 | |
__________
| |
(1) | Balance includes stock options, unvested performance shares, and unvested restricted shares granted under the Exelon LTIP or predecessor company plans including shares awarded under those plans and deferred into the stock deferral plan, and deferred stock units granted to directors as part of their compensation. Unvested performance shares are subject to performance metrics ranging from 0% to 150% of target award values and to a total shareholder return modifier. For performance shares granted in 2016, 2017 and 2018, the total includes the number of shares that could be issued pursuant to the terms of the Exelon LTIP plan, which provides that final payouts are made 50% in shares of stock and 50% in cash, and if the performance and total shareholder return modifier metrics were both at maximum, representing a best case performance scenario, for a total of 4,942,100 shares. If the performance and total shareholder return modifier metrics were at target, the number of securities to be issued for such awards would be 2,471,000. The deferred stock units granted to directors includes 433,400 shares to be issued upon the conversion of deferred stock units awarded to members of the Exelon Board of Directors. Conversion of the deferred stock units to shares occurs after a director terminates service to the Exelon board or the board of any of its subsidiary companies. See Note 19 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for additional information about the material features of the plans. |
| |
(2) | The weighted-average price reported in column B does not take the performance shares and shares credited to deferred compensation plans into account. |
| |
(3) | Includes 18,410,700 shares remaining available for issuance from the employee stock purchase plan. |
(1)Balance includes stock options, unvested performance shares, and unvested restricted stock units that were granted under the Exelon LTIP or predecessor company plans (including shares awarded under those plans and deferred into the stock deferral plan) and deferred stock units granted to directors as part of their compensation. Unvested performance shares are subject to performance metrics and to a total shareholder return modifier. Additionally, pursuant to the terms of the Exelon LTIP plan, 50% of final payouts are made in the form of shares of common stock and 50% is made in form of in cash, or if the participant has exceeded 200% of their stock ownership requirement, 100% of the final payout is made in cash. For performance shares granted in 2018, 2019, and 2020, the total includes the maximum number of shares that could be issued assuming all participants receive 50% of payouts in shares and assuming the performance and total shareholder return modifier metrics were both at maximum, representing best case performance, for a total of 6,988,082 shares. If the performance and total shareholder return modifier metrics were at "target", the number of securities to be issued for such awards would be 3,494,041. The balance also includes 450,154 shares to be issued upon the conversion of deferred stock units awarded to members of the Exelon board of directors. Conversion of the deferred stock units to shares of common stock occurs after a director terminates service to the Exelon board or the board of any of its subsidiary companies. See Note 21 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for additional information about the material features of the plans.
(2)The weighted-average price reported in column B does not take the performance shares and shares credited to deferred compensation plans into account.
(3)Includes 15,229,957 shares remaining available for issuance from the employee stock purchase plan and 4,729,509 shares remaining available for issuance to former Constellation employees with outstanding awards made under the prior Constellation LTIP.
No ComEd securities are authorized for issuance under equity compensation plans.
|
| | | | |
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE |
The additional information required by this item will be set forth under Related Persons Transactions and Director Independence in the Exelon Proxy Statement for the 20192021 Annual Meeting of Shareholders or the ComEd 20192021 Information Statement, which are incorporated herein by reference.
|
| | | | |
| ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
The information required by this item will be set forth under The Ratification of PricewaterhouseCoopers LLP as Exelon’s Independent Accountant for 20192021 in the Exelon Proxy Statement for the 20192021 Annual Meeting of Shareholders and the ComEd 20192021 Information Statement, which are incorporated herein by reference.
PART IV
| | | | | |
| ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
(a)The following documents are filed as a part of this report:
(1) Exelon
| | | | | | | | |
| (i) | | Financial Statements (Item 8): |
| |
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
| |
(a) | The following documents are filed as a part of this report: |
(1) Exelon
|
| | |
(i) | | Financial Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 8, 201924, 2021 of PricewaterhouseCoopers LLP |
| |
| | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| | |
| | Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| | |
| | Consolidated Balance Sheets at December 31, 20182020 and 20172019 |
| | |
| | Consolidated Statements of Changes in Equity for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| | |
| | Notes to Consolidated Financial Statements |
| | |
| (ii) | | Financial Statement Schedules: |
| | |
| | Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 20182020 and 20172019 and for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| | |
| | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| | |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto. |
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Statements of Operations and Other Comprehensive Income
| | | | | | | | | | | | | | | | | |
| | For the Years Ended
December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Operating expenses | | | | | |
| Operating and maintenance | $ | (2) | | | $ | 33 | | | $ | (5) | |
| Operating and maintenance from affiliates | 10 | | | 9 | | | 9 | |
| Other | 2 | | | 1 | | | 4 | |
| Total operating expenses | 10 | | | 43 | | | 8 | |
| Operating loss | (10) | | | (43) | | | (8) | |
| Other income and (deductions) | | | | | |
| Interest expense, net | (378) | | | (321) | | | (312) | |
| Equity in earnings of investments | 2,313 | | | 3,254 | | | 2,183 | |
| Interest income from affiliates, net | 30 | | | 39 | | | 42 | |
| Other, net | 15 | | | 14 | | | 3 | |
| Total other income | 1,980 | | | 2,986 | | | 1,916 | |
| Income before income taxes | 1,970 | | | 2,943 | | | 1,908 | |
| Income taxes | 7 | | | 7 | | | (97) | |
| Net income | $ | 1,963 | | | $ | 2,936 | | | $ | 2,005 | |
| Other comprehensive income (loss) | | | | | |
| Pension and non-pension postretirement benefit plans: | | | | | |
| Prior service benefit reclassified to periodic costs | $ | (40) | | | $ | (64) | | | $ | (66) | |
| Actuarial loss reclassified to periodic cost | 190 | | | 148 | | | 247 | |
| | | | | |
| Pension and non-pension postretirement benefit plan valuation adjustment | (357) | | | (289) | | | (143) | |
| Unrealized (loss) gain on cash flow hedges | (1) | | | 1 | | | 12 | |
| | | | | |
| Unrealized gain on equity investments | 0 | | | 0 | | | 1 | |
| Unrealized (loss) on foreign currency translation | 0 | | | 0 | | | (10) | |
| | | | | |
| Other comprehensive income (loss) | (208) | | | (204) | | | 41 | |
| Comprehensive income | $ | 1,755 | | | $ | 2,732 | | | $ | 2,046 | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Operating expenses | | | | | |
| Operating and maintenance | $ | (5 | ) | | $ | 10 |
| | $ | 221 |
|
| Operating and maintenance from affiliates | 9 |
| | 25 |
| | 51 |
|
| Other | 4 |
| | 4 |
| | 4 |
|
| Total operating expenses | 8 |
| | 39 |
| | 276 |
|
| Operating loss | (8 | ) | | (39 | ) | | (276 | ) |
| Other income and (deductions) | | | | | |
| Interest expense, net | (312 | ) | | (315 | ) | | (312 | ) |
| Equity in earnings of investments | 2,188 |
| | 4,414 |
| | 1,508 |
|
| Interest income from affiliates, net | 42 |
| | 40 |
| | 39 |
|
| Other, net | 3 |
| | 1 |
| | 7 |
|
| Total other income | 1,921 |
| | 4,140 |
| | 1,242 |
|
| Income before income taxes | 1,913 |
| | 4,101 |
| | 966 |
|
| Income taxes | (97 | ) | | 315 |
| | (155 | ) |
| Net income | $ | 2,010 |
| | $ | 3,786 |
| | $ | 1,121 |
|
| Other comprehensive income (loss) | | | | | |
| Pension and non-pension postretirement benefit plans: | | | | | |
| Prior service benefit reclassified to periodic costs | $ | (66 | ) | | $ | (56 | ) | | $ | (48 | ) |
| Actuarial loss reclassified to periodic cost | 247 |
| | 197 |
| | 184 |
|
| Pension and non-pension postretirement benefit plan valuation adjustment | (143 | ) | | 10 |
| | (181 | ) |
| Unrealized gain on cash flow hedges | 12 |
| | 3 |
| | 2 |
|
| Unrealized gain on marketable securities | — |
| | 6 |
| | 1 |
|
| Unrealized gain (loss) on equity investments | 1 |
| | 6 |
| | (4 | ) |
| Unrealized (loss) gain on foreign currency translation | (10 | ) | | 7 |
| | 10 |
|
| Other comprehensive income (loss) | 41 |
|
| 173 |
|
| (36 | ) |
| Comprehensive income | $ | 2,051 |
| | $ | 3,959 |
| | $ | 1,085 |
|
See the Notes to Financial Statements
486376
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Statements of Cash Flows
| | | | | | | | | | | | | | | | | |
| | For the Years Ended
December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Net cash flows provided by operating activities | $ | 3,018 | | | $ | 1,948 | | | $ | 2,576 | |
| Cash flows from investing activities | | | | | |
| | | | | |
| Changes in Exelon intercompany money pool | (477) | | | 95 | | | 1 | |
| Notes receivable from affiliates | 550 | | | 0 | | | 0 | |
| | | | | |
| Investment in affiliates | (1,969) | | | (1,071) | | | (1,231) | |
| | | | | |
| | | | | |
| Net cash flows used in investing activities | (1,896) | | | (976) | | | (1,230) | |
| Cash flows from financing activities | | | | | |
| | | | | |
| Changes in short-term borrowings | (136) | | | 136 | | | 0 | |
| Issuance of long-term debt | 2,000 | | | 0 | | | 0 | |
| | | | | |
| Retirement of long-term debt | (1,450) | | | 0 | | | 0 | |
| | | | | |
| | | | | |
| Dividends paid on common stock | (1,492) | | | (1,408) | | | (1,332) | |
| Proceeds from employee stock plans | 45 | | | 112 | | | 105 | |
| Other financing activities | (27) | | | 0 | | | (4) | |
| Net cash flows used in financing activities | (1,060) | | | (1,160) | | | (1,231) | |
| Increase (Decrease) in cash, restricted cash, and cash equivalents | 62 | | | (188) | | | 115 | |
| Cash, restricted cash, and cash equivalents at beginning of period | 1 | | | 189 | | | 74 | |
| Cash, restricted cash, and cash equivalents at end of period | $ | 63 | | | $ | 1 | | | $ | 189 | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Net cash flows provided by operating activities | $ | 2,581 |
| | $ | 1,921 |
| | $ | 1,029 |
|
| Cash flows from investing activities | | | | | |
| Changes in Exelon intercompany money pool | 1 |
| | (129 | ) | | 1,390 |
|
| Investment in affiliates | (1,236 | ) | | (1,717 | ) | | (1,757 | ) |
| Acquisition of business | — |
| | — |
| | (6,962 | ) |
| Other investing activities | — |
| | (5 | ) | | 5 |
|
| Net cash flows used in investing activities | (1,235 | ) |
| (1,851 | ) |
| (7,324 | ) |
| Cash flows from financing activities | | | | | |
| Issuance of long-term debt | — |
| | — |
| | 1,800 |
|
| Proceeds from short-term borrowings with maturities greater than 90 days | — |
| | 500 |
| | — |
|
| Retirement of long-term debt | — |
| | (569 | ) | | (46 | ) |
| Common stock issued from treasury stock | — |
| | 1,150 |
| | — |
|
| Dividends paid on common stock | (1,332 | ) | | (1,236 | ) | | (1,166 | ) |
| Proceeds from employee stock plans | 105 |
| | 150 |
| | 55 |
|
| Other financing activities | (4 | ) | | (9 | ) | | (20 | ) |
| Net cash flows (used in) provided by financing activities | (1,231 | ) | | (14 | ) | | 623 |
|
| Increase (Decrease) in cash, cash equivalents and restricted cash | 115 |
| | 56 |
| | (5,672 | ) |
| Cash, cash equivalents and restricted cash at beginning of period | 74 |
| | 18 |
| | 5,690 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 189 |
| | $ | 74 |
| | $ | 18 |
|
See the Notes to Financial Statements
487377
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets
| | | | | | | | | | | |
| | December 31, |
| (In millions) | 2020 | | 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 63 | | | $ | 1 | |
| | | |
| | | |
| Accounts receivable, net | | | |
| Other accounts receivable | 354 | | | 168 | |
| Accounts receivable from affiliates | 11 | | | 41 | |
Mark-to-market derivative assets
| 0 | | | 3 | |
| Notes receivable from affiliates | 598 | | | 679 | |
| Regulatory assets | 315 | | | 253 | |
| Other | 4 | | | 4 | |
| Total current assets | 1,345 | | | 1,149 | |
| Property, plant, and equipment, net | 46 | | | 47 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 3,816 | | | 3,772 | |
| Investments in affiliates | 43,149 | | | 42,245 | |
| Deferred income taxes | 1,625 | | | 1,524 | |
| | | |
| Notes receivable from affiliates | 324 | | | 329 | |
| Other | 312 | | | 308 | |
| Total deferred debits and other assets | 49,226 | | | 48,178 | |
| Total assets | $ | 50,617 | | | $ | 49,374 | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 189 |
| | $ | 74 |
|
| Accounts receivable, net | | | |
| Other accounts receivable | 48 |
| | 431 |
|
| Accounts receivable from affiliates | 44 |
| | 33 |
|
| Notes receivable from affiliates | 216 |
| | 217 |
|
| Regulatory assets | 182 |
| | 284 |
|
| Other | 4 |
| | 4 |
|
| Total current assets | 683 |
| | 1,043 |
|
| Property, plant and equipment, net | 48 |
| | 50 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 3,742 |
| | 3,697 |
|
| Investments in affiliates | 40,448 |
| | 39,311 |
|
| Deferred income taxes | 1,455 |
| | 1,431 |
|
| Notes receivable from affiliates | 898 |
| | 910 |
|
| Other | 235 |
| | 234 |
|
| Total deferred debits and other assets | 46,778 |
| | 45,583 |
|
| Total assets | $ | 47,509 |
| | $ | 46,676 |
|
See the Notes to Financial Statements
488378
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets
| | | | | | | | | | | |
| | December 31, |
| (In millions) | 2020 | | 2019 |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 500 | | | $ | 636 | |
| Long-term debt due within one year | 300 | | | 1,458 | |
| Accounts payable | 1 | | | 1 | |
| | | |
| Accrued expenses | 76 | | | 131 | |
| | | |
| Payables to affiliates | 457 | | | 363 | |
| Regulatory liabilities | 4 | | | 13 | |
| Pension obligations | 92 | | | 77 | |
| Other | 4 | | | 10 | |
| Total current liabilities | 1,434 | | | 2,689 | |
| Long-term debt | 7,418 | | | 5,717 | |
| | | |
| Deferred credits and other liabilities | | | |
| Regulatory liabilities | 32 | | | 31 | |
| Pension obligations | 8,351 | | | 7,960 | |
| Non-pension postretirement benefit obligations | 387 | | | 403 | |
| | | |
| Deferred income taxes | 348 | | | 263 | |
| Other | 62 | | | 87 | |
| Total deferred credits and other liabilities | 9,180 | | | 8,744 | |
| Total liabilities | 18,032 | | | 17,150 | |
| Commitments and contingencies | 0 | | 0 |
| Shareholders’ equity | | | |
| Common stock (No par value, 2,000 shares authorized, 976 shares and 973 shares outstanding at December 31, 2020 and 2019, respectively) | 19,373 | | | 19,274 | |
| Treasury stock, at cost (2 shares at December 31, 2020 and 2019) | (123) | | | (123) | |
| Retained earnings | 16,735 | | | 16,267 | |
| Accumulated other comprehensive loss, net | (3,400) | | | (3,194) | |
| Total shareholders’ equity | 32,585 | | | 32,224 | |
| | | |
| Total liabilities and shareholders’ equity | $ | 50,617 | | | $ | 49,374 | |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2018 | | 2017 |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 500 |
| | $ | 500 |
|
| Accounts payable | 1 |
| | 2 |
|
| Accrued expenses | 184 |
| | 99 |
|
| Payables to affiliates | 360 |
| | 360 |
|
| Regulatory liabilities | 15 |
| | 16 |
|
| Pension obligations | 63 |
| | 65 |
|
| Other | 14 |
| | 46 |
|
| Total current liabilities | 1,137 |
| | 1,088 |
|
| Long-term debt | 7,147 |
| | 7,161 |
|
| Deferred credits and other liabilities | | | |
| Regulatory liabilities | 32 |
| | 15 |
|
| Pension obligations | 7,795 |
| | 7,792 |
|
| Non-pension postretirement benefit obligations | 199 |
| | 322 |
|
| Deferred income taxes | 233 |
| | 220 |
|
| Other | 202 |
| | 180 |
|
| Total deferred credits and other liabilities | 8,461 |
| | 8,529 |
|
| Total liabilities | 16,745 |
| | 16,778 |
|
| Commitments and contingencies |
| |
|
| Shareholders’ equity | | | |
| Common stock (No par value, 2,000 shares authorized, 968 shares and 963 shares outstanding at December 31, 2018 and 2017, respectively) | 19,116 |
| | 18,966 |
|
| Treasury stock, at cost (2 shares at December 31, 2018 and 2017) | (123 | ) | | (123 | ) |
| Retained earnings | 14,766 |
| | 14,081 |
|
| Accumulated other comprehensive loss, net | (2,995 | ) | | (3,026 | ) |
| Total shareholders’ equity | 30,764 |
| | 29,898 |
|
| Total liabilities and shareholders’ equity | $ | 47,509 |
| | $ | 46,676 |
|
See the Notes to Financial Statements
489379
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
1. Basis of Presentation
Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation.
Exelon Corporate owns 100% of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%, and BGE, of which Exelon owns 100% of the common stock but none of BGE’s preferred stock. BGE redeemed all of its outstanding preferred stock in 2016..
2. Mergers
On March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub) and Pepco Holdings, Inc. (PHI). As a result of that merger, Merger Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and Exelon Energy Delivery Company, LLC (EEDC), a wholly owned subsidiary of Exelon which also owns Exelon's interests in ComEd, PECO and BGE (through a special purpose subsidiary in the case of BGE). See Note 5—Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the PHI Merger.
3. Debt and Credit Agreements
Short-Term Borrowings
Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had no0 outstanding commercial paper borrowings and $136 million at both December 31, 20182020 and December 31, 2017.2019, respectively.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a $500 million12-month term loan agreement for $500 million, which expired on March 22, 2018. The loan agreement was renewed annually on March 22, 2018, March 20, 2019, and March 19, 2020, respectively. The loan agreement will expire on March 21, 2019.18, 2021. Pursuant to the loan agreement, as of December 31, 2020, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1%0.65% and all indebtedness thereunder is unsecured. The loans beared interest at LIBOR plus 0.95% as of December 31, 2019 as part of the March 20, 2019 renewal. The loan agreement is reflected in Exelon’s Consolidated Balance Sheet within Short-Term borrowings.
Revolving Credit Agreements
On May 26, 2016,2018, Exelon Corporate amended itsCorporate's syndicated revolving credit facility with aggregate bank commitments of $600 million through May 26, 2021. On May 26, 2018, Exelon Corporate had its maturity date extended to May 26, 2023. As of December 31, 2018,2020, Exelon Corporation had available capacity under those commitments of $591$594 million. See Note 13—17—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon Corporation’s credit agreement.
On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility at a variable interest rate of LIBOR plus 1.75%. This facility will be used by Exelon as an additional source of short-term liquidity as needed.
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
Long-Term Debt
The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 20182020 and December 31, 2017:2019:
| | | | | | | | Maturity Date | | December 31, | | | | | Maturity
Date | | December 31, |
| | Rates | | 2018 | | 2017 | | Rates | | 2020 | | 2019 |
| Long-term debt | | | | | | | | Long-term debt | | | | | | | |
| Junior subordinated notes | | | 3.50 | % | | 2022 | | $ | 1,150 |
| | $ | 1,150 |
| Junior subordinated notes | | 3.50 | % | | 2022 | | $ | 1,150 | | | $ | 1,150 | |
| Senior unsecured notes(a) | 2.45 | % | | 7.60 | % | | 2020 - 2046 | | 5,889 |
| | 5,889 |
| Senior unsecured notes(a) | 2.45 | % | - | 7.60 | % | | 2021 - 2050 | | 6,439 | | | 5,889 | |
| Total long-term debt | | | | | 7,039 |
| | 7,039 |
| Total long-term debt | | 7,589 | | | 7,039 | |
| Unamortized debt discount and premium, net | | | | | (7 | ) | | (8 | ) | Unamortized debt discount and premium, net | | (10) | | | (7) | |
| Unamortized debt issuance costs | | | | | (47 | ) | | (49 | ) | Unamortized debt issuance costs | | (47) | | | (39) | |
| Fair value adjustment of consolidated subsidiary | | | | | 162 |
| | 179 |
| |
| Fair value adjustment | | Fair value adjustment | | 186 | | | 182 | |
| Long-term debt due within one year | | Long-term debt due within one year | | (300) | | | (1,458) | |
| Long-term debt | | | | | $ | 7,147 |
|
| $ | 7,161 |
| Long-term debt | | $ | 7,418 | | | $ | 5,717 | |
__________
| |
(a) | Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets. |
(a)Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets.
The debt maturities for Exelon Corporate for the periods 2019, 2020, 2021, 2022, 2023, 2024, 2025, and thereafter are as follows:
| | | | | |
| 2021 | $ | 300 | |
| 2022 | 1,150 | |
| 2023 | 0 | |
| 2024 | 0 | |
| 2025 | 807 | |
| Thereafter | 5,332 | |
| Total long-term debt | $ | 7,589 | |
|
| | | |
| 2019 | $ | — |
|
| 2020 | 1,450 |
|
| 2021 | 300 |
|
| 2022 | 1,150 |
|
| 2023 | — |
|
| Remaining years | 4,139 |
|
| Total long-term debt | $ | 7,039 |
|
4.3. Commitments and Contingencies
See Note 22—19—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to environmental matters and fund transfer restrictions.
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
5.4. Related Party Transactions
The financial statements of Exelon Corporate include related party transactions as presented in the tables below:
| | | | | | | | | | | | | | | | | |
| | For the Years Ended
December 31, |
| (In millions) | 2020 | | 2019 | | 2018 |
| Operating and maintenance from affiliates: | | | | | |
BSC(a) | $ | 10 | | | $ | 9 | | | $ | 11 | |
| Other | 0 | | | 0 | | | (2) | |
| Total operating and maintenance from affiliates: | $ | 10 | | | $ | 9 | | | $ | 9 | |
| Interest income from affiliates, net: | | | | | |
| Generation | $ | 29 | | | $ | 36 | | | $ | 36 | |
| BSC | 1 | | | 3 | | | 4 | |
EEDC(b) | 0 | | | 0 | | | 2 | |
| Total interest income from affiliates, net: | $ | 30 | | | $ | 39 | | | $ | 42 | |
| Equity in earnings (losses) of investments: | | | | | |
EEDC(b) | $ | 1,729 | | | $ | 2,054 | | | $ | 1,830 | |
| Generation | 589 | | | 1,125 | | | 369 | |
| UII | 0 | | | 97 | | | 0 | |
| PCI | 0 | | | 1 | | | (17) | |
| | | | | |
| Exelon Enterprises | 0 | | | (16) | | | 0 | |
| Exelon INQB8R | (6) | | | (8) | | | 0 | |
| Exelon Transmission Company | 0 | | | (2) | | | 1 | |
| Other | 1 | | | 3 | | | 0 | |
| Total equity in earnings of investments: | $ | 2,313 | | | $ | 3,254 | | | $ | 2,183 | |
| | | | | |
| Cash contributions received from affiliates | $ | 3,372 | | | $ | 2,514 | | | $ | 2,302 | |
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| (In millions) | 2018 | | 2017 | | 2016 |
| Operating and maintenance from affiliates: | | | | | |
BSC(a) | $ | 11 |
| | $ | 23 |
| | $ | 51 |
|
| Other | (2 | ) | | 2 |
| | — |
|
| Total operating and maintenance from affiliates: | $ | 9 |
| | $ | 25 |
| | $ | 51 |
|
| Interest income from affiliates, net: | | | | | |
| Generation | $ | 36 |
| | $ | 37 |
| | $ | 39 |
|
| BSC | 4 |
| | 3 |
| | — |
|
Exelon Energy Delivery Company, LLC(b) | $ | 2 |
| | $ | — |
| | $ | — |
|
| Total interest income from affiliates, net: | $ | 42 |
| | $ | 40 |
| | $ | 39 |
|
| Equity in earnings (losses) of investments: | | | | | |
Exelon Energy Delivery Company, LLC(b) | $ | 1,835 |
| | $ | 1,670 |
| | $ | 1,041 |
|
| PCI | (17 | ) | | 1 |
| | 6 |
|
| BSC | — |
| | 1 |
| | 1 |
|
| UII, LLC | — |
| | 41 |
| | (9 | ) |
| Exelon Transmission Company, LLC | 1 |
| | (10 | ) | | (13 | ) |
| Exelon Enterprise | — |
| | 1 |
| | (1 | ) |
| Generation | 369 |
| | 2,710 |
| | 483 |
|
| Total equity in earnings of investments: | $ | 2,188 |
| | $ | 4,414 |
| | $ | 1,508 |
|
| | | | | | |
| Cash contributions received from affiliates | $ | 2,302 |
| | $ | 1,879 |
| | $ | 1,912 |
|
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
| | | | December 31, | | December 31, |
| (in millions) | 2018 | | 2017 | (in millions) | 2020 | | 2019 |
| Accounts receivable from affiliates (current): | | | | Accounts receivable from affiliates (current): | | | |
BSC(a) | $ | 13 |
| | $ | 1 |
| BSC(a) | $ | 0 | | | $ | 11 | |
| Generation | 17 |
| | 21 |
| Generation | 3 | | | 13 | |
| ComEd | 4 |
| | 3 |
| ComEd | 0 | | | 2 | |
| PECO | 2 |
| | 1 |
| PECO | 1 | | | 2 | |
| BGE | 2 |
| | 1 |
| BGE | 0 | | | 1 | |
| PHISCO | 6 |
| | 6 |
| PHISCO | 6 | | | 7 | |
| Exelon Enterprises | | Exelon Enterprises | 1 | | | 0 | |
| Exelon VTI, LLC | | Exelon VTI, LLC | 0 | | | 5 | |
| Total accounts receivable from affiliates (current): | $ | 44 |
| | $ | 33 |
| Total accounts receivable from affiliates (current): | $ | 11 | | | $ | 41 | |
| Notes receivable from affiliates (current): | | | | Notes receivable from affiliates (current): | | | |
BSC(a) | $ | 116 |
| | $ | 217 |
| BSC(a) | $ | 252 | | | $ | 109 | |
Generation(c) | 100 |
| | — |
| Generation(c) | 285 | | | 558 | |
| PECO | | PECO | 40 | | | 0 | |
| PHI | | PHI | 21 | | | 12 | |
| Total notes receivable from affiliates (current): | $ | 216 |
| | $ | 217 |
| Total notes receivable from affiliates (current): | $ | 598 | | | $ | 679 | |
| Investments in affiliates: | | | | Investments in affiliates: | | | |
BSC(a) | $ | 197 |
| | $ | 196 |
| BSC(a) | $ | 196 | | | $ | 197 | |
Exelon Energy Delivery Company, LLC(b) | 26,702 |
| | 25,082 |
| |
EEDC(b) | | EEDC(b) | 30,103 | | | 28,147 | |
| Generation | | Generation | 12,400 | | | 13,484 | |
| PCI | 61 |
| | 78 |
| PCI | 62 | | | 62 | |
| UII, LLC | 268 |
| | 268 |
| |
| Exelon Transmission Company, LLC | 1 |
| | 1 |
| |
| UII | | UII | 365 | | | 365 | |
| Voluntary Employee Beneficiary Association trust | (1 | ) | | (4 | ) | Voluntary Employee Beneficiary Association trust | 0 | | | (4) | |
| Exelon Enterprises | 22 |
| | 22 |
| Exelon Enterprises | 3 | | | 6 | |
| Generation | 13,204 |
| | 13,674 |
| |
| Exelon INQB8R, LLC | | Exelon INQB8R, LLC | 23 | | | (8) | |
| Other | (6 | ) | | (6 | ) | Other | (3) | | | (4) | |
| Total investments in affiliates: | $ | 40,448 |
| | $ | 39,311 |
| Total investments in affiliates: | $ | 43,149 | | | $ | 42,245 | |
| Notes receivable from affiliates (non-current): | | | | Notes receivable from affiliates (non-current): | | | |
Generation(c) | $ | 898 |
| | $ | 910 |
| Generation(c) | $ | 324 | | | $ | 329 | |
| | Accounts payable to affiliates (current): | | | | Accounts payable to affiliates (current): | |
| UII, LLC | $ | 360 |
| | $ | 360 |
| |
| | UII | | UII | $ | 360 | | | $ | 360 | |
| BSC | | BSC | 91 | | | 0 | |
EEDC(b) | | EEDC(b) | 4 | | | 0 | |
Generation(c) | | Generation(c) | 2 | | | 0 | |
| Exelon Enterprises | | Exelon Enterprises | 0 | | | 3 | |
| Total accounts payable to affiliates (current): | | Total accounts payable to affiliates (current): | $ | 457 | | | $ | 363 | |
__________
| |
(a) | Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. |
| |
(b) | Exelon Energy Delivery Company, LLC consists of ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. |
| |
(c) | In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-Term Debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation in Exelon’s Consolidated Balance Sheets. |
(a)Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology, and supply management services. All services are provided at cost, including applicable overhead.
(b)EEDC consists of ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE.
(c)In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-Term Debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation in Exelon’s Consolidated Balance Sheets.
Exelon Corporation and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
| | | Column A | | Column B | | Column C | | Column D | | Column E | Column A | Column B | | Column C | | Column D | | Column E |
| | | | | Additions and adjustments | | | | | | | Additions and adjustments | | | | |
| Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | Description | Balance at
Beginning
of Period | | Charged to
Costs and
Expenses | | Charged
to Other
Accounts | | Deductions | | Balance at
End
of Period |
| | | (in millions) | |
| For the year ended December 31, 2018 | | | | | | | | | | | |
Allowance for uncollectible accounts(a) | | $ | 322 |
|
| $ | 159 |
|
| $ | 35 |
| (c) | $ | 197 |
| (e) | $ | 319 |
| |
| (In millions) | | (In millions) | | | | | | | | | |
| For the year ended December 31, 2020 | | For the year ended December 31, 2020 | |
Allowance for credit losses(a) | | Allowance for credit losses(a) | $ | 294 | |
| $ | 240 | | (b) | $ | (18) | | (c) | $ | 79 | | (d) | $ | 437 | |
| Deferred tax valuation allowance | | 37 |
|
| — |
|
| 5 |
|
| 7 |
| | 35 |
| Deferred tax valuation allowance | 26 | |
| 0 | |
| 1 | |
| 0 | | | 27 | |
| Reserve for obsolete materials | | 174 |
|
| 25 |
|
| (31 | ) | (d) | 12 |
| | 156 |
| Reserve for obsolete materials | 155 | |
| 128 | | (e) | (1) | | | 6 | | | 276 | |
| For the year ended December 31, 2017 | |
|
|
|
|
|
|
| |
|
| |
Allowance for uncollectible accounts(a) | | $ | 334 |
|
| $ | 126 |
|
| $ | 27 |
| (c) | $ | 165 |
| (e) | $ | 322 |
| |
| For the year ended December 31, 2019 | | For the year ended December 31, 2019 | |
| |
| |
| |
Allowance for credit losses(a) | | Allowance for credit losses(a) | $ | 319 | |
| $ | 119 | | (b) | $ | 26 | | | $ | 170 | | (d) | $ | 294 | |
| Deferred tax valuation allowance | | 20 |
|
| — |
|
| 17 |
|
| — |
| | 37 |
| Deferred tax valuation allowance | 35 | |
| 0 | |
| (9) | |
| 0 | | | 26 | |
| Reserve for obsolete materials | | 113 |
|
| 56 |
|
| 10 |
|
| 5 |
| | 174 |
| Reserve for obsolete materials | 156 | |
| 6 | |
| 0 | | | 7 | | | 155 | |
| For the year ended December 31, 2016 | |
|
|
|
|
|
|
| |
|
| |
Allowance for uncollectible accounts(a) | | $ | 284 |
|
| $ | 162 |
|
| $ | 99 |
| (b)(c) | $ | 211 |
| (e) | $ | 334 |
| |
| For the year ended December 31, 2018 | | For the year ended December 31, 2018 | |
| |
| |
| |
Allowance for credit losses(a) | | Allowance for credit losses(a) | $ | 322 | |
| $ | 159 | | (b) | $ | 35 | | | $ | 197 | | (d) | $ | 319 | |
| Deferred tax valuation allowance | | 13 |
|
| — |
|
| 10 |
| (b) | 3 |
| | 20 |
| Deferred tax valuation allowance | 37 | |
| 0 | |
| 5 | | | 7 | | | 35 | |
| Reserve for obsolete materials | | 105 |
|
| 12 |
|
| 1 |
| (b) | 5 |
| | 113 |
| Reserve for obsolete materials | 174 | |
| 25 | |
| (31) | | (f) | 12 | | | 156 | |
__________
| |
(a) | Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $13 million, $15 million, and $23 million for the years ended December 31, 2018, 2017 and 2016, respectively. |
| |
(b) | Primarily represents the addition of PHI's results as of March 23, 2016, the date of the merger |
| |
(c) | Includes charges for late payments and non-service receivables. |
| |
(d) | Primarily reflects the reclassification of assets as held for sale. |
| |
(e) | Write-off of individual accounts receivable. |
(a)Excludes the non-current allowance for credit losses related to PECO’s installment plan receivables of $5 million, $9 million, and $13 million for the years ended December 31, 2020, 2019, and 2018, respectively.
(b)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions the Utility Registrants operate in.
(c)Includes a decrease related to the sale of customer accounts receivable at Generation in the second quarter of 2020. See Note 6—Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
(d)Primarily reflects write-offs, net of recoveries of individual accounts receivable.
(e)Primarily reflects expense resulting from materials and supplies inventory reserve adjustments as a result of the decision to early retire Byron, Dresden, and Mystic 8 and 9. See Note 7—Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
(f)Primarily reflects the reclassification of assets as held for sale at Generation.
Exelon Generation Company, LLC and Subsidiary Companies
(2) Generation
| | | | | | | | |
| (i) | | Financial Statements (Item 8): |
| |
| | |
(i) | | Financial Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 8, 201924, 2021 of PricewaterhouseCoopers LLP |
| |
| | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Consolidated Balance Sheets at December 31, 20182020 and 20172019 |
| |
| | Consolidated Statements of Changes in Equity for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Notes to Consolidated Financial Statements |
| |
| (ii) | | Financial Statement Schedule: |
| |
| | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Exelon Generation Company, LLC and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
| | | Column A | | Column B | | Column C | | Column D | | Column E | Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | Additions and adjustments | | | | | | | | | Additions and adjustments | | | | |
| Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | Description | | Balance at
Beginning
of Period | | Charged to
Costs and
Expenses | | Charged
to Other
Accounts | | Deductions | | Balance at
End
of Period |
| | | (in millions) | |
| For the year ended December 31, 2018 | | | | | | | | | | | |
| Allowance for uncollectible accounts | | $ | 114 |
|
| $ | 44 |
|
| $ | 4 |
|
| $ | 58 |
| | $ | 104 |
| |
| (In millions) | | (In millions) | | | | | | | | | | |
| For the year ended December 31, 2020 | | For the year ended December 31, 2020 | |
| Allowance for credit losses | | Allowance for credit losses | | $ | 81 | |
| $ | 12 | |
| $ | (56) | | (a) | $ | 5 | | (b) | $ | 32 | |
| Deferred tax valuation allowance | | 23 |
|
| — |
|
| 3 |
| | — |
| | 26 |
| Deferred tax valuation allowance | | 24 | |
| 0 | |
| (1) | | | 0 | | | 23 | |
| Reserve for obsolete materials | | 166 |
|
| 20 |
|
| (32 | ) | (a) | 9 |
| | 145 |
| Reserve for obsolete materials | | 143 | |
| 123 | | (c) | (1) | |
| 0 | | | 265 | |
| For the year ended December 31, 2017 | |
|
|
|
|
|
|
| |
|
| |
| Allowance for uncollectible accounts | | $ | 91 |
|
| $ | 34 |
|
| $ | — |
| | $ | 11 |
| | $ | 114 |
| |
| For the year ended December 31, 2019 | | For the year ended December 31, 2019 | |
| |
| |
| |
| Allowance for credit losses | | Allowance for credit losses | | $ | 104 | |
| $ | 27 | |
| $ | (11) | | | $ | 39 | | (b) | $ | 81 | |
| Deferred tax valuation allowance | | 9 |
|
| — |
|
| 14 |
| | — |
| | 23 |
| Deferred tax valuation allowance | | 26 | |
| 0 | |
| (2) | | | 0 | | | 24 | |
| Reserve for obsolete materials | | 106 |
|
| 51 |
|
| 9 |
| | — |
| | 166 |
| Reserve for obsolete materials | | 145 | |
| 0 | |
| 0 | | | 2 | | | 143 | |
| For the year ended December 31, 2016 | |
|
|
|
|
|
|
| |
|
| |
| Allowance for uncollectible accounts | | $ | 77 |
|
| $ | 19 |
|
| $ | 3 |
|
| $ | 8 |
| | $ | 91 |
| |
| For the year ended December 31, 2018 | | For the year ended December 31, 2018 | |
| |
| |
| |
| Allowance for credit losses | | Allowance for credit losses | | $ | 114 | |
| $ | 44 | |
| $ | 4 | |
| $ | 58 | | (b) | $ | 104 | |
| Deferred tax valuation allowance | | 11 |
| | — |
| | — |
| | 2 |
| | 9 |
| Deferred tax valuation allowance | | 23 | | | 0 | | | 3 | | | 0 | | | 26 | |
| Reserve for obsolete materials | | 102 |
|
| 6 |
|
| — |
|
| 2 |
| | 106 |
| Reserve for obsolete materials | | 166 | |
| 20 | |
| (32) | | (d) | 9 | | | 145 | |
__________
| |
(a) | Primarily reflects the reclassification of assets as held for sale. |
(a)Reflects the sale of customer accounts receivable at Generation in the second quarter of 2020. See Note 6—Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
(b)Write-offs, net of recoveries of individual accounts receivable.
(c)Primarily reflects expense resulting from materials and supplies inventory reserve adjustments as a result of the decision to early retire Byron, Dresden, and Mystic 8 and 9. See Note 7—Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
(d)Primarily reflects the reclassification of assets as held for sale.
Commonwealth Edison Company and Subsidiary Companies
(3) ComEd
| | | | | | | | |
| (i) | | Financial Statements (Item 8): |
| |
| | |
(i) | | Financial Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 8, 201924, 2021 of PricewaterhouseCoopers LLP |
| |
| | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Consolidated Balance Sheets at December 31, 20182020 and 20172019 |
| |
| | Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Notes to Consolidated Financial Statements |
| |
| (ii) | | Financial Statement Schedule: |
| |
| | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Commonwealth Edison Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
| | | Column A | | Column B | | Column C | | Column D | | Column E | Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | Additions and adjustments | | | | | | | | | Additions and adjustments | | | | |
| Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | Description | | Balance at
Beginning
of Period | | Charged to
Costs and
Expenses | | Charged
to Other
Accounts | | Deductions | | Balance at
End
of Period |
| | | (in millions) | |
| (In millions) | | (In millions) | | | | | | | | | | |
| For the year ended December 31, 2020 | | For the year ended December 31, 2020 | |
| Allowance for credit losses | | Allowance for credit losses | | $ | 79 | | | $ | 54 | | (a) | $ | 13 | | | $ | 28 | | (b) | $ | 118 | |
| Reserve for obsolete materials | | Reserve for obsolete materials | | 7 | | | 3 | | | 0 | |
| 4 | | | 6 | |
| For the year ended December 31, 2019 | | For the year ended December 31, 2019 | |
| |
| Allowance for credit losses | | Allowance for credit losses | | $ | 81 | | | $ | 35 | | (a) | $ | 20 | | | $ | 57 | | (b) | $ | 79 | |
| Reserve for obsolete materials | | Reserve for obsolete materials | | 6 | | | 6 | | | 0 | |
| 5 | | | 7 | |
| For the year ended December 31, 2018 | | | | | | | | | | | For the year ended December 31, 2018 | |
| |
| Allowance for uncollectible accounts | | $ | 73 |
|
| $ | 44 |
|
| $ | 23 |
| (a) | $ | 59 |
| (b) | $ | 81 |
| |
| Allowance for credit losses | | Allowance for credit losses | | $ | 73 | | | $ | 44 | | (a) | $ | 23 | | | $ | 59 | | (b) | $ | 81 | |
| Reserve for obsolete materials | | 5 |
|
| 3 |
|
| 1 |
|
| 3 |
| | 6 |
| Reserve for obsolete materials | | 5 | | | 3 | |
| 1 | |
| 3 | | | 6 | |
| For the year ended December 31, 2017 | |
|
|
|
|
|
|
| |
|
| |
| Allowance for uncollectible accounts | | $ | 70 |
|
| $ | 39 |
|
| $ | 20 |
| (a) | $ | 56 |
| (b) | $ | 73 |
| |
| Reserve for obsolete materials | | 4 |
|
| 3 |
|
| 1 |
|
| 3 |
| | 5 |
| |
| For the year ended December 31, 2016 | |
|
|
|
|
|
|
| |
|
| |
| Allowance for uncollectible accounts | | $ | 75 |
|
| $ | 45 |
|
| $ | 23 |
| (a) | $ | 73 |
| (b) | $ | 70 |
| |
| Reserve for obsolete materials | | 3 |
|
| 4 |
|
| 1 |
|
| 4 |
| | 4 |
| |
__________
| |
(a) | Primarily charges for late payments and non-service receivables. |
| |
(b) | Write-off of individual accounts receivable. |
(a)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism. The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under such mechanism. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(b)Write-offs, net of recoveries of individual accounts receivable.
PECO Energy Company and Subsidiary Companies
(4) PECO
| | | | | | | | |
| (i) | | Financial Statements (Item 8): |
| |
| | |
(i) | | Financial Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 8, 201924, 2021 of PricewaterhouseCoopers LLP |
| |
| | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Consolidated Balance Sheets at December 31, 20182020 and 20172019 |
| |
| | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Notes to Consolidated Financial Statements |
| |
| (ii) | | Financial Statement Schedule: |
| |
| | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
PECO Energy Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
| | | Column A | | Column B | | Column C | | Column D | | Column E | Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | Additions and adjustments | | | | | | | | | Additions and adjustments | | | | |
| Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | Description | | Balance at
Beginning
of Period | | Charged to
Costs and
Expenses | | Charged
to Other
Accounts | | Deductions | | Balance at
End
of Period |
| | | (in millions) | |
| (In millions) | | (In millions) | | | | | | | | | | |
| For the year ended December 31, 2020 | | For the year ended December 31, 2020 | |
Allowance for credit losses(a) | | Allowance for credit losses(a) | | $ | 62 | |
| $ | 76 | | (b) | $ | 6 | | | $ | 20 | | (c) | $ | 124 | |
| Deferred tax valuation allowance | | Deferred tax valuation allowance | | 0 | | | 0 | | | 1 | | | 0 | | | $ | 1 | |
| Reserve for obsolete materials | | Reserve for obsolete materials | | 2 | |
| 1 | | | 0 | | | 1 | | | 2 | |
| For the year ended December 31, 2019 | | For the year ended December 31, 2019 | |
| |
Allowance for credit losses(a) | | Allowance for credit losses(a) | | $ | 61 | |
| $ | 31 | | | $ | 3 | | | $ | 33 | | (c) | $ | 62 | |
| Reserve for obsolete materials | | Reserve for obsolete materials | | 2 | |
| 0 | | | 0 | | | 0 | | | 2 | |
| For the year ended December 31, 2018 | | | | | | | | | | | For the year ended December 31, 2018 | |
| |
Allowance for uncollectible accounts(a) | | $ | 56 |
|
| $ | 33 |
|
| $ | 3 |
| (b) | $ | 31 |
| (c) | $ | 61 |
| |
Allowance for credit losses(a) | | Allowance for credit losses(a) | | $ | 56 | |
| $ | 33 | | | $ | 3 | | | $ | 31 | | (c) | $ | 61 | |
| Reserve for obsolete materials | | 2 |
|
| — |
|
| — |
|
| — |
| | 2 |
| Reserve for obsolete materials | | 2 | |
| 0 | |
| 0 | |
| 0 | | | 2 | |
| For the year ended December 31, 2017 | |
|
|
|
|
|
|
| |
|
| |
Allowance for uncollectible accounts(a) | | $ | 61 |
|
| $ | 26 |
|
| $ | 4 |
| (b) | $ | 35 |
| (c) | $ | 56 |
| |
| Reserve for obsolete materials | | 2 |
|
| — |
|
| — |
|
| — |
| | 2 |
| |
| For the year ended December 31, 2016 | |
|
|
|
|
|
|
| |
|
| |
Allowance for uncollectible accounts(a) | | $ | 83 |
|
| $ | 32 |
|
| $ | 7 |
| (b) | $ | 61 |
| (c) | $ | 61 |
| |
| Reserve for obsolete materials | | 1 |
|
| 1 |
|
| — |
|
| — |
| | 2 |
| |
__________
| |
(a) | Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $13 million, $15 million, and $23 million for the years ended December 31, 2018, 2017, and 2016, respectively. |
| |
(b) | Primarily charges for late payments. |
| |
(c) | Write-off of individual accounts receivable. |
(a)Excludes the non-current allowance for credit losses related to PECO’s installment plan receivables of $5 million, $9 million, and $13 million for the years ended December 31, 2020, 2019, and 2018, respectively.
(b)The amount charged to costs and expenses includes the amount that was reclassified to the COVID-19 regulatory asset. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(c)Write-offs, net of recoveries of individual accounts receivable.
Baltimore Gas and Electric Company and Subsidiary Companies
(5) BGE
| | | | | | | | |
| (i) | | Financial Statements (Item 8): |
| |
| | |
(i) | | Financial Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 8, 201924, 2021 of PricewaterhouseCoopers LLP |
| |
| | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 20172020, 2019 and 20162018 |
| |
| | Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 20172020, 2019 and 20162018 |
| |
| | Consolidated Balance Sheets at December 31, 20182020 and 20172019 |
| |
| | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 20172020, 2019 and 20162018 |
| |
| | Notes to Consolidated Financial Statements |
| |
| (ii) | | Financial Statement Schedule: |
| |
| | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Baltimore Gas and Electric Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
| | | Column A | | Column B | | Column C | | Column D | | Column E | Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | Additions and adjustments | | | | | | | | | Additions and adjustments | | | | |
| Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | Description | | Balance at
Beginning
of Period | | Charged to
Costs and
Expenses | | Charged
to Other
Accounts | | Deductions | | Balance at
End
of Period |
| | | (in millions) | |
| For the year ended December 31, 2018 | | | | | | | | | | | |
| Allowance for uncollectible accounts | | $ | 24 |
|
| $ | 10 |
|
| $ | (2 | ) |
| $ | 12 |
| (a) | $ | 20 |
| |
| (In millions) | | (In millions) | | | | | | | | | | |
| For the year ended December 31, 2020 | | For the year ended December 31, 2020 | |
| Allowance for credit losses | | Allowance for credit losses | | $ | 17 | |
| $ | 31 | | (a) | $ | 6 | |
| $ | 10 | | (b) | $ | 44 | |
| Deferred tax valuation allowance | | 1 |
|
| — |
|
| — |
|
| — |
| | 1 |
| Deferred tax valuation allowance | | 1 | |
| 0 | | | (1) | |
| 0 | | | 0 | |
| Reserve for obsolete materials | | — |
|
| 1 |
|
| — |
|
| — |
| | 1 |
| Reserve for obsolete materials | | 1 | |
| 0 | | | 0 | |
| 0 | | | 1 | |
| For the year ended December 31, 2017 | |
|
|
|
|
|
|
| |
|
| |
| Allowance for uncollectible accounts | | $ | 32 |
|
| $ | 8 |
|
| $ | (3 | ) |
| $ | 13 |
| (a) | $ | 24 |
| |
| For the year ended December 31, 2019 | | For the year ended December 31, 2019 | |
| |
| |
| Allowance for credit losses | | Allowance for credit losses | | $ | 20 | |
| $ | 8 | | (a) | $ | 7 | |
| $ | 18 | | (b) | $ | 17 | |
| Deferred tax valuation allowance | | 1 |
|
| — |
|
| — |
|
| — |
| | 1 |
| Deferred tax valuation allowance | | 1 | |
| 0 | | | 0 | |
| 0 | | | 1 | |
| Reserve for obsolete materials | | — |
|
| — |
|
| — |
|
| — |
| | — |
| Reserve for obsolete materials | | 1 | |
| 0 | | | 0 | |
| 0 | | | 1 | |
| For the year ended December 31, 2016 | |
|
|
|
|
|
|
| |
|
| |
| Allowance for uncollectible accounts | | $ | 49 |
|
| $ | 1 |
|
| $ | 9 |
|
| $ | 27 |
| (a) | $ | 32 |
| |
| For the year ended December 31, 2018 | | For the year ended December 31, 2018 | |
| |
| |
| Allowance for credit losses | | Allowance for credit losses | | $ | 24 | |
| $ | 10 | | (a) | $ | (2) | |
| $ | 12 | | (b) | $ | 20 | |
| Deferred tax valuation allowance | | 1 |
| | — |
| | — |
| | — |
| | 1 |
| Deferred tax valuation allowance | | 1 | | | 0 | | | 0 | | | 0 | | | 1 | |
| Reserve for obsolete materials | | — |
| | — |
| | — |
| | — |
| | — |
| Reserve for obsolete materials | | 0 | | | 1 | | | 0 | | | 0 | | | 1 | |
__________
| |
(a) | Write-off of individual accounts receivable. |
(a)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the MDPSC.
(b)Write-offs, net of recoveries of individual accounts receivable.
Pepco Holdings LLC and Subsidiary Companies
(6) PHI
| | | | | | | | |
| (i) | | Financial Statements (Item 8): |
| |
| | |
(i) | | Successor Company Financial Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 8, 201924, 2021 of PricewaterhouseCoopers LLP |
| |
| | Consolidated Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 20182020, 2019, and 2017 and for the Period March 24, 2016 to December 31, 20162018 |
| |
| | Consolidated Statements of Cash Flows for the Years Ended December 31, 20182020, 2019, and 2017 and for the Period March 24, 2016 to December 31, 20162018 |
| |
| | Consolidated Balance Sheets at December 31, 20182020 and 20172019 |
| |
| | Consolidated Statements of Changes in Equity for the Years Ended December 31, 20182020, 2019, and 2017 and for the Period March 24, 2016 to December 31, 20162018 |
| |
| | Notes to Consolidated Financial Statements |
| | |
| (ii) | | Predecessor Company Financial Statements (Item 8): |
| | |
| | Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP |
| | |
| | Consolidated Statements of Operations and Comprehensive Income for the Period January 1, 2016 to March 23, 2016 |
| | |
| | Consolidated Statements of Cash Flows for the Period January 1, 2016 to March 23, 2016 |
| | |
| | Consolidated Statements of Changes in Equity for the Period January 1, 2016 to March 23, 2016 |
| | |
| | Notes to Consolidated Financial Statements |
| |
(iii) | | Successor Financial Statement Schedule: |
| |
| | Schedule II – II—Valuation and Qualifying Accounts - Forfor the Years Ended December 31, 20182020, 2019, and 2017 and the Period March 24, 2016 to December 31, 20162018 |
| | |
(iv) | | Predecessor Financial Statement Schedule: |
| |
| | Schedule II – Valuation and Qualifying Accounts - For the Period January 1, 2016 to March 23, 2016 |
| | |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Pepco Holdings LLC and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
| | | Column A | | Column B | | Column C | | Column D | | Column E | Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | Additions and adjustments | | | | | | | | | Additions and adjustments | | | | |
| Description | | Balance at
Beginning
of Period | | Charged to
Costs and
Expenses | | Charged
to Other
Accounts | | Deductions | | Balance at
End
of Period | Description | | Balance at
Beginning
of Period | | Charged to
Costs and
Expenses | | Charged
to Other
Accounts | | Deductions | | Balance at
End
of Period |
| (In millions) | | (In millions) | | | | | | | | | | |
| For the year ended December 31, 2020 | | For the year ended December 31, 2020 | |
| Allowance for credit losses | | Allowance for credit losses | | $ | 53 | | | $ | 69 | | (a) | $ | 13 | | | $ | 16 | | (b) | $ | 119 | |
| | | (in millions) | |
For the Year Ended December 31, 2018 (Successor) | | | | | | | | | | | |
| Allowance for uncollectible accounts | | $ | 55 |
| | $ | 28 |
| | $ | 7 |
| (a) | $ | 37 |
| (b) | $ | 53 |
| |
| Reserve for obsolete materials | | Reserve for obsolete materials | | 3 | | | 0 | | | 0 | | | 1 | | | 2 | |
| For the year ended December 31, 2019 | | For the year ended December 31, 2019 | |
| Allowance for credit losses | | Allowance for credit losses | | $ | 53 | | | $ | 17 | | (a) | $ | 7 | | | $ | 24 | | (c) | $ | 53 | |
| Deferred tax valuation allowance | | 13 |
| | — |
| | 2 |
| | 7 |
| | 8 |
| Deferred tax valuation allowance | | 8 | | | 0 | | | (8) | | | 0 | | | 0 | |
| Reserve for obsolete materials | | 2 |
| | — |
| | — |
| | — |
| | 2 |
| Reserve for obsolete materials | | 2 | | | 1 | | | 0 | | | 0 | | | 3 | |
For the Year Ended December 31, 2017 (Successor) | | | | | | | | | | | |
| Allowance for uncollectible accounts | | $ | 80 |
| | $ | 19 |
| | $ | 6 |
| (a) | $ | 50 |
| (b) | $ | 55 |
| |
| For the year ended December 31, 2018 | | For the year ended December 31, 2018 | |
| Allowance for credit losses | | Allowance for credit losses | | $ | 55 | | | $ | 28 | | (a) | $ | 7 | | | $ | 37 | | (c) | $ | 53 | |
| Deferred tax valuation allowance | | 10 |
| | — |
| | 3 |
| | — |
| | 13 |
| Deferred tax valuation allowance | | 13 | | | 0 | | | 2 | | | 7 | | | 8 | |
| Reserve for obsolete materials | | 2 |
| | 2 |
| | — |
| | 2 |
| | 2 |
| Reserve for obsolete materials | | 2 | | | 0 | | | 0 | | | 0 | | | 2 | |
March 24, 2016 to December 31, 2016 (Successor) | | | | | | | | | | | |
| Allowance for uncollectible accounts | | $ | 52 |
| | $ | 65 |
| | $ | 5 |
| (a) | $ | 42 |
| (b) | $ | 80 |
| |
| Deferred tax valuation allowance | | 63 |
| | — |
| | (53 | ) | | — |
| | 10 |
| |
| Reserve for obsolete materials | | — |
| | 1 |
| | — |
| | (1 | ) | | 2 |
| |
January 1, 2016 to March 23, 2016 (Predecessor) | | | | | | | | | | | |
| Allowance for uncollectible accounts | | $ | 56 |
| | $ | 16 |
| | $ | 2 |
| (a) | $ | 22 |
| (b) | $ | 52 |
| |
| Deferred tax valuation allowance | | 63 |
| | — |
| | — |
| | — |
| | 63 |
| |
| Reserve for obsolete materials | | — |
| | — |
| | — |
| | ��� |
| | — |
| |
__________
| |
(a) | Primarily charges for late payments. |
| |
(b) | Write-off of individual accounts receivable. |
(a)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions Pepco, DPL, and ACE operate in.
(b)Write-offs, net of recoveries of individual accounts receivable.
(c)Write-offs of individual accounts receivable.
Potomac Electric Power Company
(7) Pepco
| | | | | | | | |
| (i) | | Financial Statements (Item 8): |
| |
| | |
(i) | | Financial Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 8, 201924, 2021 of PricewaterhouseCoopers LLP |
| |
| | Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 20172020, 2019 and 20162018 |
| |
| | Statements of Cash Flows for the Years Ended December 31, 2018, 20172020, 2019 and 20162018 |
| |
| | Balance Sheets at December 31, 20182020 and 20172019 |
| |
| | Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 20172020, 2019 and 20162018 |
| |
| | Notes to Financial Statements |
| |
| (ii) | | Financial Statement Schedule: |
| |
| | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Potomac Electric Power Company
Schedule II – Valuation and Qualifying Accounts
| | | Column A | | Column B | | Column C | | Column D | | Column E | Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | Additions and adjustments | | | | | | | | | Additions and adjustments | | | | |
| Description | | Balance at
Beginning
of Period | | Charged to
Costs and
Expenses | | Charged
to Other
Accounts | | Deductions | | Balance at
End
of Period | Description | | Balance at
Beginning
of Period | | Charged to
Costs and
Expenses | | Charged
to Other
Accounts | | Deductions | | Balance at
End
of Period |
| (In millions) | | (In millions) | | | | | | | | | | |
| For the year ended December 31, 2020 | | For the year ended December 31, 2020 | |
| Allowance for credit losses | | Allowance for credit losses | | $ | 20 | | | $ | 25 | | (a) | $ | 5 | | | $ | 5 | | (b) | $ | 45 | |
| | | (in millions) | |
| Reserve for obsolete materials | | Reserve for obsolete materials | | 1 | | | 0 | | | 0 | | | 0 | | | 1 | |
| For the year ended December 31, 2019 | | For the year ended December 31, 2019 | |
| Allowance for credit losses | | Allowance for credit losses | | $ | 21 | | | $ | 7 | | (a) | $ | 2 | | | $ | 10 | | (c) | $ | 20 | |
| | Reserve for obsolete materials | | Reserve for obsolete materials | | 1 | | | 0 | | | 0 | | | 0 | | | 1 | |
| For the year ended December 31, 2018 | | | | | | | | | | | For the year ended December 31, 2018 | |
| Allowance for uncollectible accounts | | $ | 21 |
| | $ | 11 |
| | $ | 3 |
| (a) | $ | 14 |
| (b) | $ | 21 |
| |
| Allowance for credit losses | | Allowance for credit losses | | $ | 21 | | | $ | 11 | | (a) | $ | 3 | | | $ | 14 | | (c) | $ | 21 | |
| | Reserve for obsolete materials | | 1 |
| | — |
| | — |
| | — |
| | 1 |
| Reserve for obsolete materials | | 1 | | | 0 | | | 0 | | | 0 | | | 1 | |
| For the year ended December 31, 2017 | | | | | | | | | | | |
| Allowance for uncollectible accounts | | $ | 29 |
| | $ | 8 |
| | $ | 2 |
| (a) | $ | 18 |
| (b) | $ | 21 |
| |
| Reserve for obsolete materials | | 1 |
| | 1 |
| | — |
| | 1 |
| | 1 |
| |
| For the year ended December 31, 2016 | | | | | | | | | | | |
| Allowance for uncollectible accounts | | $ | 17 |
| | $ | 29 |
| | $ | 3 |
| (a) | $ | 20 |
| (b) | $ | 29 |
| |
| Reserve for obsolete materials | | — |
| | 3 |
| | — |
| | 2 |
| | 1 |
| |
__________
| |
(a) | Primarily charges for late payments. |
| |
(b) | Write-off of individual accounts receivable. |
(a)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the DCPSC and MDPSC.
(b)Write-offs, net of recoveries of individual accounts receivable.
(c)Write-off of individual accounts receivable.
Delmarva Power & Light Company
(8) DPL
| | | | | | | | |
| (i) | | Financial Statements (Item 8): |
| |
| | |
(i) | | Financial Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 8, 201924, 2021 of PricewaterhouseCoopers LLP |
| |
| | Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2018, 20172020, 2019 and 20162018 |
| |
| | Statements of Cash Flows for the Years Ended December 31, 2018, 20172020, 2019 and 20162018 |
| |
| | Balance Sheets at December 31, 20182020 and 20172019 |
| |
| | Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 20172020, 2019 and 20162018 |
| |
| | Notes to Financial Statements |
| |
| (ii) | | Financial Statement Schedule: |
| |
| | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Delmarva Power & Light Company
Schedule II – Valuation and Qualifying Accounts
|
| | | | | | | | | | | | | | | | | | | | |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | Additions and adjustments | | | | |
| Description | | Balance at
Beginning
of Period | | Charged to
Costs and
Expenses | | Charged
to Other
Accounts | | Deductions | | Balance at
End
of Period |
| | | (in millions) |
| For the year ended December 31, 2018 | | | | | | | | | | |
| Allowance for uncollectible accounts | | $ | 16 |
| | $ | 6 |
| | $ | 2 |
| (a) | $ | 11 |
| (b) | $ | 13 |
|
| Reserve for obsolete materials | | — |
| | — |
| | — |
| | — |
| | — |
|
| For the year ended December 31, 2017 | | | | | | | | | | |
| Allowance for uncollectible accounts | | $ | 24 |
| | $ | 3 |
| | $ | 2 |
| (a) | $ | 13 |
| (b) | $ | 16 |
|
| Reserve for obsolete materials | | — |
| | 1 |
| | — |
| | 1 |
| | — |
|
| For the year ended December 31, 2016 | | | | | | | | | | |
| Allowance for uncollectible accounts | | $ | 17 |
| | $ | 23 |
| | $ | 2 |
| (a) | $ | 18 |
| (b) | $ | 24 |
|
| Reserve for obsolete materials | | — |
| | 1 |
| | — |
| | 1 |
| | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | Additions and adjustments | | | | |
| Description | | Balance at
Beginning
of Period | | Charged to
Costs and
Expenses | | Charged
to Other
Accounts | | Deductions | | Balance at
End
of Period |
| (In millions) | | | | | | | | | | |
| For the year ended December 31, 2020 | | | | | | | | | | |
| Allowance for credit losses | | $ | 15 | | | $ | 16 | | (a) | $ | 4 | | | $ | 4 | | (b) | $ | 31 | |
| | | | | | | | | | |
| | | | | | | | | | |
| For the year ended December 31, 2019 | | | | | | | | | | |
| Allowance for credit losses | | $ | 13 | | | $ | 4 | | (a) | $ | 3 | | | $ | 5 | | (c) | $ | 15 | |
| | | | | | | | | | |
| | | | | | | | | | |
| For the year ended December 31, 2018 | | | | | | | | | | |
| Allowance for credit losses | | $ | 16 | | | $ | 6 | | (a) | $ | 2 | | | $ | 11 | | (c) | $ | 13 | |
| | | | | | | | | | |
| | | | | | | | | | |
__________
| |
(a) | Primarily charges for late payments. |
| |
(b) | Write-off of individual accounts receivable. |
(a)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the DPSC and MDPSC.
(b)Write-offs, net of recoveries of individual accounts receivable.
(c)Write-off of individual accounts receivable.
Atlantic City Electric Company and Subsidiary Company
(9) ACE
| | | | | | | | |
| (i) | | Financial Statements (Item 8): |
| |
| | |
(i) | | Financial Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 8, 201924, 2021 of PricewaterhouseCoopers LLP |
| |
| | Consolidated Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Consolidated Balance Sheets at December 31, 20182020 and 20172019 |
| |
| | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Notes to Consolidated Financial Statements |
| |
| (ii) | | Financial Statement Schedule: |
| |
| | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 20172020, 2019, and 20162018 |
| |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Atlantic City Electric Company and Subsidiary Company
Schedule II – Valuation and Qualifying Accounts
| | | Column A | | Column B | | Column C | | Column D | | Column E | Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | Additions and adjustments | | | | | | | | | Additions and adjustments | | | | |
| Description | | Balance at
Beginning
of Period | | Charged to
Costs and
Expenses | | Charged
to Other
Accounts | | Deductions | | Balance at
End
of Period | Description | | Balance at
Beginning
of Period | | Charged to
Costs and
Expenses | | Charged
to Other
Accounts | | Deductions | | Balance at
End
of Period |
| (In millions) | | (In millions) | | | | | | | | | | |
| For the year ended December 31, 2020 | | For the year ended December 31, 2020 | |
| Allowance for credit losses | | Allowance for credit losses | | $ | 18 | | | $ | 28 | | (a) | $ | 4 | | | $ | 7 | | (b) | $ | 43 | |
| | | (in millions) | |
| Reserve for obsolete materials | | Reserve for obsolete materials | | 1 | | | 0 | | | 0 | | | 1 | | | 0 | |
| For the year ended December 31, 2019 | | For the year ended December 31, 2019 | |
| Allowance for credit losses | | Allowance for credit losses | | $ | 19 | | | $ | 5 | | (a) | $ | 2 | | | $ | 8 | | (c) | $ | 18 | |
| | Reserve for obsolete materials | | Reserve for obsolete materials | | 1 | | | 0 | | | 0 | | | 0 | | | 1 | |
| For the year ended December 31, 2018 | | | | | | | | | | | For the year ended December 31, 2018 | |
| Allowance for uncollectible accounts | | $ | 18 |
| | $ | 11 |
| | $ | 2 |
| (a) | $ | 12 |
| (b) | $ | 19 |
| |
| Allowance for credit losses | | Allowance for credit losses | | $ | 18 | | | $ | 11 | | (a) | $ | 2 | | | $ | 12 | | (c) | $ | 19 | |
| | Reserve for obsolete materials | | 1 |
| | — |
| | — |
| | — |
| | 1 |
| Reserve for obsolete materials | | 1 | | | 0 | | | 0 | | | 0 | | | 1 | |
| For the year ended December 31, 2017 | | | | | | | | | | | |
| Allowance for uncollectible accounts | | $ | 27 |
| | $ | 8 |
| | $ | 2 |
| (a) | $ | 19 |
| (b) | $ | 18 |
| |
| Reserve for obsolete materials | | 1 |
| | — |
| | — |
| | — |
| | 1 |
| |
| For the year ended December 31, 2016 | | | | | | | | | | | |
| Allowance for uncollectible accounts | | $ | 17 |
| | $ | 32 |
| | $ | 2 |
| (a) | $ | 24 |
| (b) | $ | 27 |
| |
| Reserve for obsolete materials | | — |
| | 1 |
| | — |
| | — |
| | 1 |
| |
__________
| |
(a) | Primarily charges for late payments. |
| |
(b) | Write-off of individual accounts receivable. |
(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge. The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under such mechanism. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(b)Write-offs, net of recoveries of individual accounts receivable.
(c)Write-off of individual accounts receivable.
Exhibits required by Item 601 of Regulation S-K:
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis and the relevant registrant agrees to furnish a copy of any such instrument to the Commission upon request.
|
| | | | | | | | | | | | | | | | |
| Exhibit No. | Description | | | | |
| | | | | |
| |
| | | | | |
| |
| | | | | |
| |
| | | | | |
| |
| | | | | |
| |
| | | | | |
| Master Agreement, dated as of October 26, 2010, by and between Electricite de France, S.A. and Constellation Energy Group, Inc. (Designated as Exhibit(File No. 2.1 to the Current Report on001-12869, Form 8-K dated November 1, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869)Exhibit 2.1). |
| | | | | |
| Put Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., Constellation Nuclear, LLC, and Constellation Energy Nuclear Group, LLC. (Designated as Exhibit(File No. 2.1 to the Current Report on001-12869, Form 8-K dated November 8, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869)Exhibit 2.1). |
| | | | | |
| Contribution Agreement, dated as of February 4, 2010, by and among Constellation Energy Group, Inc., Baltimore Gas and Electric Company and RF HoldCo LLC. (Designated as Exhibit(File No. 99.2 to the Current Report on001-12869, Form 8-K dated February 4, 2010, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910)Exhibit 99.2). |
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| |
| | | | | |
| |
| | | | | |
| | | | | | | | | | | | | | | | | |
| Exhibit No. | Description |
| 4-1 | First and Refunding Mortgage dated May 1, 1923 between The Counties Gas and Electric Company (predecessor to PECO Energy Company) and Fidelity Trust Company, Trustee (U.S. Bank National Association, as current successor trustee), (Registration No. 2-2281, Exhibit B-1).(a) |
| | | | | |
4-1-24-1-1 | Reserved. |
| |
4-1-3 | Supplemental Indentures to PECO Energy Company’s First and Refunding Mortgage: |
|
| | | | | |
| Dated as of | | File Reference | | Exhibit No. |
| May 1, 1927 | | 2-2881(a)
| | B-1(c) |
| | | |
| March 1, 1937 | | 2-2881(a)
| | B-1(g) |
| | | |
| December 1, 1941 | | 2-4863(a) | | B-1(h) |
| | | |
| November 1, 1944April 15, 2004 | | | | B-1(i) |
| | | |
| December 1, 1946September 15, 2006 | | | | 7-1(j) |
| | | |
| March 1, 2007 | | | | |
| | | |
| September 1, 19572012 | | | | 2(b)-17 |
| | | |
| May 1, 1958September 15, 2013 | | | | 2(b)-18 |
| | | |
| MarchSeptember 1, 19682014 | | | | 2(b)-24 |
| | | |
| March 1, 1981 | | | | 4-46 |
| | | |
| March 1, 1981 | | 2-72802(a)
| | 4-47 |
| | | | | |
| December 1, 1984 | | 1-01401, 1984 Form 10-K(a)
| | 4-2(b) |
| | | |
| March 1, 1993 | | 1-01401, 1992 Form 10-K(a)
| | 4(e)-86 |
| | | |
|
| | | | | |
| Dated as of | | File Reference | | Exhibit No. |
| May 1, 1993 | | 1-01401, March 31, 1993 Form 10-Q(a)
| | 4(e)-88 |
| | | |
| May 1, 1993 | | 1-01401, March 31, 1993 Form 10-Q(a)
| | 4(e)-89 |
| | | |
| April 15, 2004 | | 0-6844, September 30, 2004 Form 10-Q(a)
| | 4-1-1 |
| | | |
| September 15, 2006 | | | | |
| | | |
| March 1, 2007 | | | | |
| | | |
| March 15, 2009 | | | | |
| | | |
| September 1, 2012 | | | | |
| | | |
| September 15, 2013 | | | | |
| | | |
| September 1, 2014 | |
| | |
| | | | | |
| September 15, 2015 | |
| | |
| | | | | |
| September 1, 2016 | | | | |
| | | | | |
| September 1, 2017 | | | | |
| |
| February 1, 2018 | |
| | |
| | | | | |
| September 1, 2018 | | | | |
| |
Exhibit No. | DescriptionAugust 15, 2019 | | | | |
| | | | | |
| June 1, 2020 | | | | |
| | | | | | | | | | | | | | | | | |
| Exhibit No. | Description |
| |
| |
| 4-3 | Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Mellon Trust Company of Illinois, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944. (Registration No. 2-60201, Form S-7, Exhibit 2-1).(a) |
| | | | | | | | | | | | | | | | | |
| Exhibit No. | Description |
| 4-3-1 | Supplemental Indentures to Commonwealth Edison Company Mortgage. |
| | | |
| Dated as of | | File Reference | | Exhibit No. |
| August 1, 1946 | | 2-60201, Form S-7(a)
| | 2-1 |
| | | |
| April 1, 1953 | | 2-60201, Form S-7(a)
| | 2-1 |
| | | |
| March 31, 1967 | | 2-60201, Form S-7(a)
| | 2-1 |
| | | |
|
| | | | | |
| Dated as of | | File Reference | | Exhibit No. |
| April 1, 1967January 13, 2003 | | | | 2-1 |
| February 28, 1969 | | 2-60201, Form S-7(a)
| | 2-1 |
| February 22, 2006 | | | | |
| May 29, 1970 | | 2-60201, Form S-7(a)
| | 2-1 |
| August 1, 2006 | | | | |
| June 1, 1971 | | 2-60201, Form S-7(a)
| | 2-1 |
| September 15, 2006 | | | | |
| April 1, 1972 | | 2-60201, Form S-7(a)
| | 2-1 |
| March 1, 2007 | | | | |
| May 31, 1972 | | 2-60201, Form S-7(a)
| | 2-1 |
| August 30, 2007 | | | | |
| June 15, 1973 | | 2-60201, Form S-7(a)
| | 2-1 |
| December 20, 2007 | | | | |
| May 31, 1974 | | 2-60201, Form S-7(a)
| | 2-1 |
| March 10, 2008 | | |
| June 13, 1975 | | | | 2-1 |
| | | | | |
| May 28, 1976 | | | | 2-1 |
|
| | | | | |
| June 3, 1977July 12, 2010 | | 2-60201, Form S-7(a)
| | 2-1 |
| | | |
| May 17, 1978 | | 2-99665, Form S-3(a)
| | 4-3 |
| | | |
| August 31, 1978 | | 2-99665, Form S-3(a)
| | 4-3 |
| | | |
| June 18, 1979 | | 2-99665, Form S-3(a)
| | 4-3 |
| | | |
| June 20, 1980 | | 2-99665, Form S-3(a)
| | 4-3 |
| | | |
| April 16, 1981 | | 2-99665, Form S-3(a)
| | 4-3 |
| | | |
| April 30, 1982 | | 2-99665, Form S-3(a)
| | 4-3 |
| | | |
| April 15, 1983 | | 2-99665, Form S-3(a)
| | 4-3 |
| | | |
| April 13, 1984 | | 2-99665, Form S-3(a)
| | 4-3 |
| | | |
| April 15, 1985 | | 2-99665, Form S-3(a)
| | 4-3 |
| | | |
| April 15, 1986 | | 33-6879, Form S-3(a)
| | 4-9 |
| | | |
| January 13, 2003 | | | | |
| | | |
| February 22, 2006 | | | | |
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| August 1, 2006 | | | | |
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| September 15, 2006August 22, 2011 | | | | |
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| September 17, 2012 | | | | |
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| MarchAugust 1, 20072013 | | | | |
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| August 30, 2007January 2, 2014 | | | | |
| | | |
| December 20, 2007 | | | | |
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| March 10, 2008 | | | | |
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| Dated as of | | File Reference | | Exhibit No. |
| July 12, 2010 | | | | |
| | | |
| August 22, 2011 | | | | |
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| September 17, 2012 | | | | |
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| August 1, 2013 | | | | |
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| January 2, 2014 | | | | |
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| October 28, 2014 | | | | |
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| February 18, 2015 | | | | |
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| November 4, 2015 | | | | |
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| June 15, 2016 | | | | |
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| August 9, 2017 | | | | |
| | | | | | | | | | | | | | | | | |
| Dated as of | | File Reference | | Exhibit No. |
| February 6, 2018 | | | | |
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| July 26, 2018 | | | | |
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| February 7, 2019 | | | | |
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| October 29, 2019 | | | | |
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| February 10, 2020 | | | | |
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| Exhibit No. | Description |
| Instrument of Registration,Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage of Commonwealth Edison Company dated July 1, 1923, and Indentures Supplemental thereto, regarding corporate trustee (File No. 1-1839, 2001001-01839, Form 10-K dated April 1, 2002, Exhibit 4-4-2)4.4.2). |
| |
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| |
4-4 | Indenture dated as of September 1, 1987 between Commonwealth Edison Company and Citibank, N.A. (U.S. Bank National Association, as current successor trustee), Trustee relating to Notes (Registration No. 33-20619, Form S-3, Exhibit 4-13).(a)
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Exhibit No. | Description |
| |
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| |
| PECO Energy Capital Trust IV Amended and Restated Declaration of Trust among PECO Energy Company, as Sponsor, U.S. Bank Trust National Association, as Delaware Trustee and Property Trustee, and J. Barry Mitchell, George R. Shicora and Charles S. Walls as Administrative Trustees dated as of June 24, 2003 (File No. 000-16844, JuneForm 10-Q dated July 30, 2003, Form 10-Q, Exhibit 4.3). |
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Exhibit No. | Description |
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| |
| Indenture, dated as of September 30, 2013, among Continental Wind, LLC, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 333-85496, Form 8-K dated September 30, 2013, Exhibit No. 4.1). |
| |
4-274-26 | Indenture dated July 1, 1985, between Baltimore Gas and Electric Company and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3, File No. 2-98443); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit 4(a) to the Current Report on Form 8-K, dated November 13, 1987, File No. 1-1910) and as of January 26, 1993 (Designated as Exhibit 4(b) to the Current Report on Form 8-K, dated January 29, 1993, filed by Baltimore Gas and Electric Company, File No. 1-1910).(a) |
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| Supplemental Indenture No. 1, dated as of October 1, 2009, to the Indenture and Security Agreement dated as of July 9, 2009, between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(c) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910). |
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Exhibit No. | Description |
| Officers’ Certificate, dated December 14, 2010, establishing the 5.15% Notes due December 1, 2020 of Constellation Energy Group, Inc., with the form of Notes attached thereto. (Designated as Exhibit(File No. 4 (b) to the Current Report on001-12869, Form 8-K dated December 14, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869)Exhibit 4 (b)). |
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Exhibit No. | Description |
4-424-39 | Mortgage and Deed of Trust, dated July 1, 1936, of Potomac Electric Power Company to The Bank of New York Mellon as successor trustee, securing First Mortgage Bonds of Potomac Electric Power Company, and Supplemental Indenture dated July 1, 1936 (File No. 2-2232, Registration Statement dated June 19, 1936, Exhibit B-4).(a) |
| |
| | | | | |
4-42-1Exhibit No. | Description |
| 4-39-1 | Supplemental Indentures to Potomac Electric Power Company Mortgage. |
| | | | | | | | | | | | | | | | | |
| Dated as of | | File Reference | | Exhibit No. |
| December 10, 1939 | | Form 8-K dated January 3, 1940(a) | | B |
| | | | | |
| Dated as ofMarch 16, 2004 | | File Reference | | Exhibit No. |
| | | | | |
| December 10, 1939 | | | | B |
| | | | | |
| July 15, 1942 | | 2-5032, Amendment No 2. To Registration Statement, 8/24/42(a)4.3 | | B-1 |
| | | | | |
| October 15, 1947 | | Form 8-K , 12/8/47(a)
| | A |
| | | | | |
| December 31, 1948 | | Form 10-K, 4/13/49(a)
| | A-2 |
| | | | | |
| December 31, 1949 | | Form 8-K, 2/8/50(a)
| | (a)-1 |
| | | | | |
| February 15, 1951 | | Form 8-K, 3/9/51(a)
| | (a) |
| | | | | |
| February 16, 1953 | | Form 8-K, 3/5/53(a)
| | (a)-1 |
| | | | | |
| March 15, 1954 and March 15, 1955 | | 2-11627, Registration Statement, 5/2/55(a)
| | 4-B |
| | | | | |
| March 15, 1956 | | Form 10-K, 4/4/56(a)
| | C |
| | | | | |
| April 1, 1957 | | 2-13884, Registration Statement, 2/5/58(a)
| | 4-B |
| | | | | |
| May 1, 1958 | | 2-14518, Registration Statement, 11/10/58(a)
| | 2-B |
| | | | | |
| May 1, 1959 | | 2-15027, Amendment No. 1 to Registration Statement, 5/13/59(a)
| | 4-B |
| | | | | |
| May 2, 1960 | | 2-17286, Registration Statement, 11/9/60(a)
| | 2-B |
| | | | | |
| April 3, 1961 | | Form 10-K, 4/24/61(a)
| | A-1 |
| | | | | |
| May 1, 1962 | | 2-21037, Registration Statement, 1/25/63(a)
| | 2-B |
| | | | | |
| May 1, 1963 | | 2-21961, Registration Statement, 12/19/63(a)
| | 4-B |
| | | | | |
| April 23, 1964 | | 2-22344, Registration Statement, 4/24/64(a)
| | 2-B |
| | | | | |
| May 3, 1965 | | 2-24655, Registration Statement, 3/16/66(a)
| | 2-B |
| | | | | |
| June 1, 1966 | | Form 10-K, 4/11/67(a)
| | 1 |
| | | | | |
| April 28, 1967 | | 2-26356, Post-Effective Amendment No. 1 to Registration Statement, 5/3/67(a)
| | 2-B |
|
| | | | | |
| Dated as ofMay 24, 2005 | | File Reference | | Exhibit No. |
| | | | | |
| July 3, 1967 | | 2-28080, Registration Statement, 1/25/68(a)
| | 2-B |
| | | | | |
| May 1, 1968 | | 2-31896, Registration Statement, 2/28/69(a)
| | 2-B |
| | | | | |
| June 16, 1969 | | 2-36094, Registration Statement, 1/27/70(a)
| | 2-B |
| | | | | |
| May 15, 1970 | | 2-38038, Registration Statement, 7/27/70(a)
| | 2-B |
| | | | | |
| September 1, 1971 | | 2-45591, Registration Statement, 9/1/72(a)
| | 2-C |
| | | | | |
| June 17, 1981 | | Amendment No. 1 to Form 8-A, 6/18/81(a)
| | 2 |
| | | | | |
| November 1, 1985 | | Form 8-A, 11/1/85(a)
| | 2B |
| | | | | |
| September 16, 1987 | | 33-18229, Registration Statement, 10/30/87(a)
| | 4-B |
| | | | | |
| May 1, 1989 | | 33-29382, Registration Statement, 6/16/89(a)
| | 4-C |
| | | | | |
| May 21, 1991 | | Form 10-K, 3/27/92(a)
| | 4 |
| | | | | |
| May 7, 1992 | | Form 10-K, 3/26/93(a)
| | 4 |
| | | | | |
| September 1, 1992 | | Form 10-K, 3/26/93(a)
| | 4 |
| | | | | |
| November 1, 1992 | | Form 10-K, 3/26/93(a)
| | 4 |
| | | | | |
| July 1, 1993 | | 33-49973, Registration Statement, 8/11/93(a)
| | 4.4 |
| | | | | |
| February 10, 1994 | | | | |
| | | | | |
| February 11, 1994 | | | | |
| | | | | |
| October 2, 1997 | | | | |
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| November 17, 2003 | | | | |
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| March 16, 2004 | | | | |
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| May 24, 2005 | | | | |
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| April 1, 2006 | | | | |
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| November 13, 2007 | | | | |
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| March 24, 2008 | | | | |
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|
| | | | | |
| Dated as ofNovember 13, 2007 | | File Reference | | Exhibit No. |
| December 3, 2008 | | | | |
| | | | | |
| March 28, 2012 | | | | |
| | | | | |
| March 11, 2013 | | | | |
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| November 14, 2013 | | | | |
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| March 11, 2014 | | | | |
| | | | | |
| March 9, 2015 | | | | |
| | | | | |
| May 15, 2017 | | | | |
| | | | | |
| June 1, 2018 | | | |
|
|
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Exhibit No. | DescriptionMarch 24, 2008 | | | | |
4-43 | | | | | |
| December 3, 2008 | | | | |
| | | | | |
| March 28, 2012 | | | | |
| | | | | |
| March 11, 2013 | | | | |
| | | | | |
| November 14, 2013 | | | | |
| | | | | |
| March 11, 2014 | | | | |
| | | | | |
| March 9, 2015 | | | | |
| | | | | |
| May 15, 2017 | | | | |
| | | | | |
| June 1, 2018 | | | | |
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| May 2, 2019 | | | | |
| | | | | |
| February 12, 2020 | | | | |
| | | | | | | | | | | | | | | | | |
| Exhibit No. | Description |
| 4-40 | Indenture, dated as of July 28, 1989, between Potomac Electric Power Company and The Bank of New York Mellon, Trustee, with respect to Medium-Term Note Program (File No. 001-01072, Form 8-K dated June 21, 1990, Exhibit 4).(a) |
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4-45Exhibit No. | Description |
| 4-42 | Mortgage and Deed of Trust of Delaware Power & Light Company to The Bank of New York Mellon (ultimate successor to the New York Trust Company), as trustee, dated as of October 1, 1943, and copies of the First through Sixty-Eighth Supplemental Indentures thereto (File No. 33-1763, Registration Statement dated November 27, 1985, Exhibit 4-A)(a) |
| |
4-45-14-42-1 | Supplemental Indentures to Delmarva Power & Light Company Mortgage. |
| | | | | |
| Dated as of | | File Reference | | Exhibit No. |
| | | | | |
| January 1, 1986 | | 33-39756, Registration Statement, 4/03/91(a)
| | 4-B |
| | | | | |
| June 1, 1986 | | 33-24955, Registration Statement, 10/13/88(a)
| | 4-B |
| | | | | |
| January 1, 1987 | | 33-24955, Registration Statement, 10/13/88(a)
| | 4-B |
| | | | | |
| September 1, 1987 | | 33-24955, Registration Statement, 10/13/88(a)
| | 4-B |
| | | | | |
| October 1, 1987 | | 33-24955, Registration Statement, 10/13/88(a)
| | 4-B |
| | | | | |
| January 1, 1988 | | 33-24955, Registration Statement, 10/13/88(a)
| | 4-B |
| | | | | |
|
| | | | | |
| Dated as of | | File Reference | | Exhibit No. |
| December 1, 1988 | | 33-39756, Registration Statement, 4/03/91(a)
| | 4-D |
| | | | | |
| January 1, 1989 | | 33-39756, Registration Statement, 4/03/91(a)
| | 4-E |
| | | | | |
| March 1, 1990 | | 33-39756, Registration Statement, 4/03/91(a)
| | 4-F |
| | | | | |
| January 1, 1991 | | 33-46892, Registration Statement, 4/1/92(a)
| | 4-E |
| | | | | |
| July 1, 1991 | | 33-46892, Registration Statement, 4/1/92(a)
| | 4-F |
| | | | | |
| February 1, 1992 | | 33-49750, Registration Statement, 7/17/92(a)
| | 4 |
| | | | | |
| May 1, 1992 | | 33-57652, Registration Statement, 1/29/93(a)
| | 4-G |
| | | | | |
| October 1, 19921993 | | 33-63582, Registration Statement, 5/28/93(a)
| | 4-H |
| | | | | |
| January 1, 1993 | | 33-50453, Registration Statement, 10/1/93(a)
| | 99 |
| | | | | |
| June 1, 1993 | | 33-53855, Registration Statement 1/30/95dated January 30, 1995(a) | | 4-J |
| | | | | |
| July 1, 1993 | | 33-53855, Registration Statement, 1/30/95(a)
| | 4-K |
| | | | | |
| October 1, 1993 | | 33-53855, Registration Statement, 1/30/95(a)
| | 4-L |
| | | | | |
| January 1, 1994 | | 33-53855, Registration Statement, 1/30/95(a)
| | 4-M |
| | | | | |
| October 1, 1994 | | 33-53855, Registration Statement, 1/30/95(a)
| | 4-N |
| | | | | |
| January 1, 1995 | | 333-00505, Registration Statement, 1/29/96(a)
| | 4-K |
| | | | | |
| June 1, 1995 | | 333-00505, Registration Statement, 1/29/96(a)
| | 4-L |
| | | | | |
| January 1, 1996 | | 333-24059, Registration Statement, 3/27/97(a)
| | 4-L |
| | | | | |
| January 1, 1997 | | | | |
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| January 1, 1998 | | | | |
| | | | | |
| January 1, 1999 | | | | |
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| January 1, 2000 | | | | |
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| | | | | |
| Dated as ofOctober 1, 1994 | | File Reference | | Exhibit No. |
| January 1, 2001 | | | | |
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| January 1, 2002 | | | | |
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| January 1, 2003 | | | | |
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| January 1, 2004 | | | | |
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| January 1, 2005 | | | | |
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| January 1, 2006 | | | | |
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| January 1, 2007 | | | | |
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| January 1, 2008 | | | | |
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| January 1, 2009 | | | | |
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| September 22, 2009 | | | | |
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| January 1, 2010 | | | | |
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| January 1, 2011 | | | | |
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| May 2, 2011 | | | | |
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| January 1, 2012 | | | | |
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| June 19, 2012 | | | | |
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| January 1, 2013 | | | | |
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| November 7, 2013 | | | | |
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| January 1, 2014 | | | | |
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| June 2, 2014 | | | | |
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| January 1, 2015 | | | | |
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| May 4, 2015 | | | | |
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| January 1, 2016 | | | | |
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| December 5, 2016 | | | | |
| | | | | |
| 4-N |
| | | | | |
| Dated as ofJanuary 1, 1997 | | File Reference | | Exhibit No. |
| | | | | |
| November 7, 2013 | | | | |
| | | | | |
| June 2, 2014 | | | | |
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| May 4, 2015 | | | | |
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| December 5, 2016 | | | | |
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| April 5, 2017 | | | | |
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| April 3, 2018 | | | | |
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| June 1, 2018 | | | | |
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| April 3, 2019 | | | | |
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| May 2, 2019 | | | | |
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| March 18, 2020 | | | | |
| | | | | |
| June 1, 2020 | | | | |
|
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| Exhibit No. | Description | |
4-464-43 | Indenture between Delmarva Power & Light Company and The Bank of New York Mellon Trust Company, N.A. (ultimate successor to Manufacturers Hanover Trust Company), as trustee, dated as of November 1, 1988 (File No. 33-46892, Registration Statement dated April 1, 1992, Exhibit 4-G).(a) |
| | | | | | |
4-474-44 | Mortgage and Deed of Trust, dated January 15, 1937, between Atlantic City Electric Company and The Bank of New York Mellon (formerly Irving Trust Company), as trustee (File No. 2-66280, Registration Statement dated December 21, 1979, Exhibit 2(a)).(a) |
| | | | | | |
4-47-14-44-1 | Supplemental Indentures to Atlantic City Electric Company Mortgage. |
| | | | | | |
| Dated as of | | File Reference | | Exhibit No. | |
| | | | | | |
| June 1, 1949 | | 2-66280, Registration Statement 12/21/79dated December 21, 1979(a) | | 2(b) | |
| | | | | | |
| July 1, 1950 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| November 1, 1950 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| March 1, 1952 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| January 1, 1953 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| March 1, 1954 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| March 1, 1955 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| January 1, 1957 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| April 1, 1958 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| April 1, 1959 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| March 1, 1961 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| July 1, 1962 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| March 1, 1963 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
|
| | | | | | |
| Dated as of | | File Reference | | Exhibit No. | |
| February 1, 1966 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| April 1, 1970 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| September 1, 1970 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| May 1, 1971 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| April 1, 1972 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| June 1, 1973 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| January 1, 1975 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| May 1, 1975 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| December 1, 1976 | | 2-66280, Registration Statement, 12/21/79(a)
| | 2(b) | |
| | | | | | |
| January 1, 1980 | | Form 10-K, 3/25/81(a)
| | 4(e) | |
| | | | | | |
| May 1, 1981 | | Form 10-Q, 8/10/81(a)
| | 4(a) | |
| | | | | | |
| November 1, 1983 | | Form 10-K, 3/30/84(a)
| | 4(d) | |
| | | | | | |
| April 15, 1984 | | Form 10-Q, 5/14/84(a)
| | 4(a) | |
| | | | | | |
| July 15, 1984 | | Form 10-Q, 8/13/84(a)
| | 4(a) | |
| | | | | | |
| October 1, 1985 | | Form 10-Q, 11/12/85(a)
| | 4 | |
| | | | | | |
| May 1, 1986 | | Form 10-Q, 5/12/86(a)
| | 4 | |
| | | | | | |
| July 15, 1987 | | Form 10-K, 3/28/88(a)
| | 4(d) | |
| | | | | | |
| October 1, 1989 | | Form 10-Q for quarter ended 9/30/89(A)
| | 4(a) | |
| | | | | | |
| March 1, 1991 | | Form 10-K 3/28/91dated March 28, 1991(a) | | 4(d)(1) | |
| | | | | | |
| May 1, 1992 | | 33-49279, Registration Statement, 1/6/93(a)
| | 4(b) | |
| | | | | | |
| January 1, 1993 | | | | | |
| | | | | | |
| August 1, 1993 | | Form 10-Q, 11/12/93(a)
| | 4(a) | |
| | | | | | |
| September 1, 1993 | | Form 10-Q, 11/12/93(a)
| | 4(b) | |
| | | | | | |
| November 1, 1993 | | Form 10-K, 3/29/94(a)
| | 4(c)(1) | |
| | | | | | |
| June 1, 1994 | | Form 10-Q, 8/14/94(a)
| | 4(a) | |
| | | | | | |
| October 1, 1994 | | Form 10-Q, 11/14/94(a)
| | 4(a) | |
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|
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| Dated as ofApril 1, 2004 | | File Reference | | Exhibit No. | |
| November 1, 1994 | | Form 10-K, 3/21/95(a)
| | 4(c)(1) | |
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| March 1, 1997 | | | | | |
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| April 1, 2004 | | | | | |
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| August 10, 2004 | | | | | |
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| March 8, 2006 | | | | | |
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| November 6, 2008 | | | | | |
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| March 29, 2011 | | | | | |
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| August 18, 2014 | | | | | |
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| December 1, 2015 | | | | | |
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| October 9, 2018 | | | | | |
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| March 8, 2006 | | | | | |
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| March 29, 2011 | | | | | |
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| August 18, 2014 | | | | | |
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| December 1, 2015 | | | | | |
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| October 9, 2018 | | | | | |
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| May 2, 2019 | | | | | |
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| June 1, 2020 | | | | | |
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| |
Exhibit No. | Description |
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| Second Supplemental Indenture, dated April 3, 2017, between Exelon and The Bank of New York Mellon Trust Company, N.A., as trustee, to that certain Indenture (For Unsecured Subordinated Debt Securities), dated June 17, 2014 (File No. 001-16169, Form 8-K dated April 4, 2017, Exhibit 4.3). |
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| Exhibit No. | Description |
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| CreditPollution Control Facilities Loan Agreement, dated as of September 18, 2014, among ExGen Texas Power, LLC, ExGen Texas Power Holdings, LLC, Wolf Hollow I Power, LLC, Colorado Bend I Power, LLC, Laporte Power, LLC, Handley Power, LLCJune 1, 2020, between The Pollution Control Financing Authority of Salem County and Mountain Creek Power, LLC, the lenders party thereto from time to time, Bank of America, N.A., as administrative agent and collateral agent, and Wilmington Trust, National Association, as depositary agent.Atlantic City Electric (File No. 1-16169,001-03559, Form 8-K dated September 18, 2014,June 2, 2020, Exhibit 10.1)4.1). |
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10-4 | Reserved. |
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Exhibit No. | Description |
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10-33 | Reserved. |
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| Amendment No. 3 to Credit Agreement dated as of March 23, 2011 among Exelon Corporation, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated August 10, 2013, Exhibit No. 99-1)99.1). |
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Exhibit No. | Description |
| Amendment No. 1 to Credit Agreement, dated as of December 21, 2011, to the Credit Agreement dated as of March 23, 2011, among Exelon Generation Company, LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 4-6)4.6). |
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Exhibit No. | Description |
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| Second Amended and Restated Operating Agreement, dated as of November 6, 2009, by and among Constellation Energy Nuclear Group, LLC, Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Development Inc., and for certain limited purposes, E.D.F. International S.A. and Constellation Energy Group, Inc. (Designated as Exhibit(File No. 10.1 to the Current Report on001-12869, Form 8-K dated November 12, 2009, filed by Constellation Energy Group, Inc., File No. 1-12869)Exhibit 10.1). |
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| Amendment No. 1 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit(File No. 10(s) to the Annual Report on001-12869, Form 10-K for the year ended December 31, 2010, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910)dated March 3, 2011, Exhibit 10(s)). |
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Exhibit No. | Description |
| Amendment No. 2 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit(File No. 10(t) to the Annual Report on001-12869, Form 10-K for the year ended December 31, 2010, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910)dated March 3, 2011, Exhibit 10(t)). |
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| Amendment No. 3 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit(File No. 10.1 to the Current Report on001-12869, Form 8-K dated November 3, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869)Exhibit 10.1). |
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| Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., and Constellation Energy Group, Inc. (Designated as Exhibit(File No. 10.2 to the Current Report on001-12869, Form 8-K dated November 3, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869)Exhibit 10.2). |
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10-64 - 10-70 | Reserved. |
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| 364-Day Bridge Term Loan Agreement, dated as of May 30, 2014, among Exelon Corporation, as Borrower, the various financial institutions named therein, as Lenders, and Barclays Bank PLC, as Administrative Agent (File No. 001-16169, Form 8-K dated April 30, 2014, Exhibit No. 10.1). |
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| Amendment No. 4 to Credit Agreement, dated May 30, 2014, among Exelon Corporation, as Borrower, the financial institutions signatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit 10.2). |
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| Amendment No. 4 to Credit Agreement, dated May 30, 2014, among Exelon Generation Company, LLC, as Borrower, the financial institutions signatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit 10.3). |
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| Amendment No. 3 to Credit Agreement, dated May 30, 2014, among PECO Energy Company, as Borrower, the financial institutions signatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit 10.4). |
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| Amendment No. 2 to Credit Agreement, dated as of May 30, 2014, among Baltimore Gas and Electric Company, as Borrower, the financial institutions signatory therein, as Lenders and The Royal Bank of Scotland plc, as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit 10.5).
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| Exhibit No. | Description |
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| Purchase Agreement, dated as of April 20, 2010, by and among Pepco Holdings, Inc., Conectiv, LLC, Conectiv Energy Holding Company, LLC and New Development Holdings, LLC (File No. 001-31403, Form 8-K dated July 8, 2010, Exhibit 2.1). |
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| Purchase Agreement, dated March 9, 2015, among Potomac Electric Power Company and BNY Mellon Capital Markets, LLC, Morgan Stanley & Co. LLC, and RBS Securities Inc., as representatives of the several underwriters named therein (File No. 001-01072, Form 8-K dated March 10, 2015, Exhibit 1.1). |
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| Purchase Agreement, May 4, 2015, among Delmarva Power & Light Company and J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and Scotia Capital (USA) Inc., as representatives of the several underwriters named therein (File No. 001-01405, Form 8-K dated May 5, 2015, Exhibit 1.1). |
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| $300,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto, dated July 30, 2015 (File No. 001-31403, Form 8-K dated July 30, 2015, Exhibit 10). |
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| $500,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto, dated January 13, 2016 (File No. 001-31403, Form 8-K dated January 14, 2016, Exhibit 10). |
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| Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the lenders party thereto, Wells Fargo Bank, National Association, as agent, issuer and swingline lender, Bank of America, N.A., as syndication agent and issuer, The Royal Bank of Scotland plc and Citicorp USA, Inc., as co-documentation agents, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner and Smith Incorporated, as active joint lead arrangers and joint book runners, and Citigroup Global Markets Inc. and RBS Securities, Inc. as passive joint lead arrangers and joint book runners (File No. 001-31403, Form 10-Q dated August 3, 2011, Exhibit 10.1). |
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| First Amendment, dated as of August 2, 2012, to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various financial institutions party thereto, Wells Fargo Bank, National Association, as agent, issuer of letters of credit and swingline lender, Bank of America, N.A., as syndication agent and issuer of letters of credit, and The Royal Bank of Scotland plc and Citibank, N.A., as co-documentation agents (File No. 001-31403, Form 10-K dated March 1, 2013, Exhibit 10.25.1). |
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Exhibit No. | Description |
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| Amendment and Consent to Second Amended and Restated Credit Agreement, dated as of May 20, 2014, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated May 20, 2014, Exhibit 10.1). |
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| Exhibit No. | Description |
| Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 1, 2015, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated May 1, 2015, Exhibit 10.1). |
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| Consent, dated as of October 29, 2015, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated October 29, 2015, Exhibit 10.1). |
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| Amendment No. 7 to Credit Agreement, dated as of March 23, 2011, among Exelon Corporation, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated May 27, 2016, Exhibit 99.1). |
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| Amendment No. 7 to Credit Agreement, dated as of March 23, 2011, among Exelon Generation Company, LLC, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 333-85496, Form 8-K dated May 27, 2016, Exhibit 99.2). |
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| Amendment No. 4 to Credit Agreement, dated as of March 23, 2011, among Commonwealth Edison Company, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 333-85496, Form 8-K dated May 27, 2016, Exhibit 99.3). |
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| Amendment No. 6 to Credit Agreement, dated as of March 23, 2011, among PECO Energy Company, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 000-16844, Form 8-K dated May 27, 2016, Exhibit 99.4). |
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| Amendment No. 5 to Credit Agreement, dated as of March 23, 2011, among Baltimore Gas and Electric Company, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-01910, Form 8-K dated May 27, 2016, Exhibit 99.5). |
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| Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, among Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, as Borrowers, the various financial institutions named therein, as Lenders, and Wells Fargo Bank, National Association, as Administrative Agent (File No. 001-31403, Form 8-K dated May 27, 2016, Exhibit 99.6). |
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Exhibit No. | Description |
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| Credit Agreement, dated as of November 28, 2017, as thereafter amended and conformed among ExGen Renewables IV, LLC, ExGen Renewables IV Holding, LLC, Morgan Stanley Senior Funding, Inc. as administrative agent, Wilmington Trust, National Association, as depository bank and collateral agent, and the lenders and other agents party thereto. (Certain portions of this exhibit have been omitted by redacting a portion of text, as indicated by asterisks in the text. This exhibit has been filed separately with the U.S. Securities and Exchange Commission pursuant to a request for confidential treatment.) |
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| Receivables Purchase Agreement, dated as of April 8, 2020, among Constellation NewEnergy, Inc. as servicer, and NewEnergy Receivables LLC, as seller, MUFG Bank, LTD., as Agent, the Conduits party thereto, the Financial Institutions party thereto and the Purchaser Agents party thereto (File No. 001-16169, Form 8-K dated April 9, 2020, Exhibit 10.1). |
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| Credit Agreement, among ExGen Renewables IV, LLC, the lenders party thereto, Jefferies Finance LLC, as administrative agent, and Wilmington Trust, National Association, as depositary ban and collateral agent, dated December 15, 2020 (File No. 333-85496, Form 8-K dated December 15, 2020, Exhibit 1.1). |
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| Exhibit No. | Description |
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| Subsidiaries |
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| Consent of Independent Registered Public Accountants |
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Exhibit No. | Description |
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| Power of Attorney (Exelon Corporation) |
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| 24-11 | Reserved. |
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| 24-13 | Reserved. |
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| Exhibit No. | Description |
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| Power of Attorney (Commonwealth Edison Company) |
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24-23 | Reserved. |
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24-24 | Reserved. |
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| 24-24 | Reserved. |
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| Power of Attorney (PECO Energy Company) |
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Exhibit No. | Description |
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| 24-26 | Reserved. |
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| Power of Attorney (Baltimore Gas and Electric Company) |
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| Power of Attorney (Pepco Holdings LLC) |
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| Exhibit No. | Description |
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| Power of Attorney (Potomac Electric Power Company) |
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| Power of Attorney (Delmarva Power & Light Company) |
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Exhibit No. | Description |
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| Power of Attorney (Atlantic City Electric Company) |
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Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Annual Report on Form 10-K for the year ended December 31, 20182020 filed by the following officers for the following registrants: |
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| Exhibit No. | Description |
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| Exhibit No. | Description |
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Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Annual Report on Form 10-K for the year ended December 31, 20182020 filed by the following officers for the following registrants: |
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| Exhibit No. | Description |
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Exhibit No. | Description |
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101.INS | XBRL Instance |
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101.SCH | XBRL Taxonomy Extension Schema |
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101.CAL | XBRL Taxonomy Extension Calculation |
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101.DEF | XBRL Taxonomy Extension Definition |
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101.LAB | XBRL Taxonomy Extension Labels |
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101.PRE | XBRL Taxonomy Extension Presentation |
__________ | |
* | Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees. |
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(a) | These filings are not available electronically on the SEC website as they were filed in paper previous to the electronic system that is currently in place. |
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101.INS
| Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
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| 101.SCH | Inline XBRL Taxonomy Extension Schema Document. |
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| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document. |
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| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document. |
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| 101.LAB | Inline XBRL Taxonomy Extension Labels Linkbase Document. |
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| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document. |
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| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
__________
* Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees.
** Filed herewith.
(a)These filings are not available electronically on the SEC website as they were filed in paper previous to the electronic system that is currently in place.
| | | | | |
| ITEM 16. | FORM 10-K SUMMARY |
All Registrants
Registrants may voluntarily include a summary of information required by Form 10-K under this Item 16. The Registrants have elected not to include such summary information.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 8th24th day of February, 2019.2021.
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| EXELON CORPORATION | |
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| By: | | /s/ CHRISTOPHER M. CRANE | |
| Name: | | Christopher M. Crane | |
| Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 8th24th day of February, 2019.2021.
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| Signature | | Title |
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| /s/ CHRISTOPHER M. CRANE | | President, and Chief Executive Officer (Principal Executive Officer) and Director |
| Christopher M. Crane | |
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| /s/ JOSEPH NIGRO | | Senior Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
| Joseph Nigro | |
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| /s/ FABIAN E. SOUZA | | Senior Vice President and Corporate Controller (Principal Accounting Officer) |
| Fabian E. Souza | |
This annual report has also been signed below by Thomas S. O'Neill,Gayle E. Littleton, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
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| Anthony K. Anderson
Ann C. Berzin
Laurie Brlas
Christopher M. Crane
Yves C. de Balmann
Nicholas DeBenedictis
Linda P. Jojo
| | Paul L. Joskow
Robert J. Lawless
Richard W. Mies
John W. Rogers, Jr.
Mayo A. Shattuck III
Stephen D. Steinour
John F. Young
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By:Anthony K. Anderson
Ann C. Berzin
Laurie Brlas
Yves C. de Balmann
Nicholas DeBenedictis
Linda P. Jojo | | /s/ THOMAS S. O'NEILL | | February 8, 2019Paul L. Joskow
Robert J. Lawless
John M. Richardson
Marjorie Rodgers Cheshire
Mayo A. Shattuck III
John F. Young |
Name: |
|
Thomas S. O'Neill |
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| By: | | /s/ GAYLE E. LITTLETON | | February 24, 2021 |
| Name: | | Gayle E. Littleton | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 8th24th day of February, 2019.
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| EXELON GENERATION COMPANY, LLC | |
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| By: | | /s/ KENNETH W. CORNEWCHRISTOPHER M. CRANE | |
| Name: | | Kenneth W. CornewChristopher M. Crane | |
| Title: | | President and ChiefPrincipal Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 8th24th day of February, 2019.2021.
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| Signature | | Title |
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/s/ KENNETH W. CORNEWCHRISTOPHER M. CRANE | | President and ChiefPrincipal Executive Officer (Principal Executive Officer) |
Kenneth W. CornewChristopher M. Crane | |
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| /s/ BRYAN P. WRIGHT | | Senior Vice President and Chief Financial Officer (Principal Financial Officer) |
| Bryan P. Wright | |
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| /s/ MATTHEW N. BAUER | | Vice President and Controller (Principal Accounting Officer) |
Matthew N. Bauer
| |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 8th24th day of February, 2019.
|
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| COMMONWEALTH EDISON COMPANY | |
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| By: | | /s/ JOSEPH DOMINGUEZ | |
| Name: | | Joseph Dominguez | |
| Title: | | Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 8th24th day of February, 2019.
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| Signature | | Title |
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| /s/ JOSEPH DOMINGUEZ | | Chief Executive Officer (Principal Executive Officer) and Director |
| Joseph Dominguez | |
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| /s/ JEANNE M. JONES | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) |
| Jeanne M. Jones | |
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/s/ GERALDSTEVEN J. KOZELCICHOCKI | | Vice President and ControllerDirector, Accounting (Principal Accounting Officer) |
GeraldSteven J. KozelCichocki | |
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/s/ CHRISTOPHER M. CRANE | | Chairman and Director |
Christopher M. Crane | | |
This annual report has also been signed below by Joseph Dominguez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
|
| | |
James W. Compton
Christopher M. Crane
A. Steven Crown
Nicholas DeBenedictis
| | Peter V. Fazio, Jr.
Michael H. Moskow
Anne R. Pramaggiore
|
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By:Calvin G. Butler
James W. Compton
Christopher M. Crane
A. Steven Crown
| | Nicholas DeBenedictis
Peter V. Fazio, Jr.
Michael H. Moskow |
| | | | | | | | | | | | | | |
| By: | | /s/ JOSEPH DOMINGUEZ | | February 8, 201924, 2021 |
| Name: | | Joseph Dominguez | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 8th24th day of February, 2019.
|
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| PECO ENERGY COMPANY | |
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| By: | | /s/ MICHAEL A. INNOCENZO | |
| Name: | | Michael A. Innocenzo | |
| Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 8th24th day of February, 2019.
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| Signature | | Title |
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| /s/ MICHAEL A. INNOCENZO | | President, and Chief Executive Officer (Principal Executive Officer) and Director |
| Michael A. Innocenzo | |
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| /s/ ROBERT J. STEFANI | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) |
| Robert J. Stefani | |
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/s/ SCOTT A. BAILEYCAROLINE FULGINITI | | Vice President and ControllerDirector, Accounting (Principal Accounting Officer) |
Scott A. BaileyCaroline Fulginiti | |
| | |
/s/ CHRISTOPHER M. CRANE | | Chairman and Director |
Christopher M. Crane | | |
This annual report has also been signed below by Michael A. Innocenzo, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
|
| | |
Christopher M. Crane | | John S. Grady |
M. Walter D’Alessio | | Rosemarie B. Greco |
Nicholas DeBenedictis | | Charisse R. Lillie |
Nelson A. Diaz | | Anne R. Pramaggiore |
|
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By:Calvin G. Butler | | John S. Grady |
| Christopher M. Crane | | Rosemarie B. Greco |
| Nicholas DeBenedictis | | Charisse R. Lillie |
| Nelson A. Diaz | | |
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| | | | | | | | | | | | | | |
| By: | | /s/ MICHAEL A. INNOCENZO | | February 8, 201924, 2021 |
| Name: | | Michael A. Innocenzo | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 8th24th day of February, 2019.
|
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| BALTIMORE GAS AND ELECTRIC COMPANY | |
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| By: | | /s/ CALVIN G. BUTLER, JR.CARIM V. KHOUZAMI | |
| Name: | | Calvin G. Butler, Jr.Carim V. Khouzami | |
| Title: | | Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 8th24th day of February, 2019.2021.
|
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| Signature | | Title |
| |
/s/ CALVIN G. BUTLER, JR.CARIM V. KHOUZAMI | | Chief Executive Officer (Principal Executive Officer) and Director |
Calvin G. Butler, Jr.Carim V. Khouzami | |
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| /s/ DAVID M. VAHOS | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) |
| David M. Vahos | |
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/s/ ANDREW W. HOLMESJASON T. JONES | | Vice President and ControllerDirector, Accounting (Principal Accounting Officer) |
Andrew W. HolmesJason T. Jones | |
| | |
/s/ CHRISTOPHER M. CRANE | | Chairman and Director |
Christopher M. Crane | | |
This annual report has also been signed below by Calvin G. Butler, Jr.,Carim V. Khouzami, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
|
| | |
Ann C. Berzin | | Joseph Haskins, Jr. |
Christopher M. Crane | | Anne R. Pramaggiore |
Michael E. Cryor | | Michael D. Sullivan |
James R. Curtiss | | Maria Harris Tildon |
|
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By:Ann C. Berzin | | /s/ CALVIN G. BUTLER, JR. | | February 8, 2019James R. Curtiss |
Name: | | Calvin G. Butler | | Joseph Haskins, Jr. |
| Christopher M. Crane | | Michael D. Sullivan |
| Michael E. Cryor | | Maria Harris Tildon |
| | |
| | | | | | | | | | | | | | |
| By: | | /s/ CARIM V. KHOUZAMI | | February 24, 2021 |
| Name: | | Carim V. Khouzami | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 8th24th day of February, 2019.
|
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| PEPCO HOLDINGS LLC | |
| | |
| By: | | /s/ DAVID M. VELAZQUEZ | |
| Name: | | David M. Velazquez | |
| Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 8th24th day of February, 2019.2021.
|
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| Signature | | Title |
| |
| /s/ DAVID M. VELAZQUEZ | | President, and Chief Executive Officer (Principal Executive Officer), and Director |
| David M. Velazquez | |
| |
| /s/ PHILLIP S. BARNETT | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
|
| Phillip S. Barnett | |
| |
/s/ ROBERT M. AIKENJULIE E. GIESE | | Vice President and ControllerDirector, Accounting (Principal Accounting Officer) |
Robert M. AikenJulie E. Giese | |
| | |
/s/ CHRISTOPHER M. CRANE | | Chairman and Director |
Christopher M. Crane | |
This annual report has also been signed below by David M. Velazquez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
| | | | | | | | |
| Calvin. G. Butler | | Michael E. Cryor |
| Christopher M. Crane | | Ernest Dianastasis |
| Linda W. Cropp | | Debra P. DiLorenzo |
| | |
| | |
Christopher M. Crane | | Ernest Dianastasis |
Linda W. Cropp | | Debra P. DiLorenzo |
Michael E. Cryor | | Anne R. Pramaggiore |
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| By: | | /s/ DAVID M. VELAZQUEZ | | February 8, 201924, 2021 |
| Name: | | David M. Velazquez | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 8th24th day of February, 2019.
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| POTOMAC ELECTRIC POWER COMPANY | |
| | |
| By: | | /s/ DAVID M. VELAZQUEZ | |
| Name: | | David M. Velazquez | |
| Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 8th24th day of February, 2019.2021.
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| | | | | | | |
| Signature | | Title |
| |
| /s/ DAVID M. VELAZQUEZ | | President, and Chief Executive Officer (Principal Executive Officer), and Director |
| David M. Velazquez | |
| |
| /s/ PHILLIP S. BARNETT | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
|
| Phillip S. Barnett | |
| |
/s/ ROBERT M. AIKENJULIE E. GIESE | | Vice President and ControllerDirector, Accounting (Principal Accounting Officer) |
Robert M. AikenJulie E. Giese | |
| | |
/s/ CHRISTOPHER M. CRANE | | Chairman |
Christopher M. Crane | |
This annual report has also been signed below by David M. Velazquez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
| | | | | | | | |
| J. Tyler Anthony | | Christopher M. Crane |
| Phillip S. Barnett | | Melissa A. Lavinson |
| Calvin G. Butler | | Kevin M. McGowan |
| | |
| | |
J. Tyler Anthony | | Melissa A. Lavinson |
Phillip S. Barnett | | Kevin M. McGowan |
Christopher M. Crane | | Anne R. Pramaggiore |
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| | | | | | | | | | | | | |
| By: | | /s/ DAVID M. VELAZQUEZ | | February 8, 201924, 2021 |
| Name: | | David M. Velazquez | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 8th24th day of February, 2019.
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| DELMARVA POWER & LIGHT COMPANY | |
| | |
| By: | | /s/ DAVID M. VELAZQUEZ | |
| Name: | | David M. Velazquez | |
| Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 8th24th day of February, 2019.2021.
|
| | | | | | | |
| Signature | | Title |
| |
| /s/ DAVID M. VELAZQUEZ | | President, and Chief Executive Officer (Principal Executive Officer), and Director |
| David M. Velazquez | |
| |
| /s/ PHILLIP S. BARNETT | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
|
| Phillip S. Barnett | |
| |
/s/ ROBERT M. AIKENJULIE E. GIESE | | Vice President and ControllerDirector, Accounting (Principal Accounting Officer) |
Robert M. AikenJulie E. Giese | |
| | |
/s/ CHRISTOPHER M. CRANE | | Chairman |
Christopher M. Crane | |
This annual report has also been signed below by David M. Velazquez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
| | | | | | | | |
| Calvin G. Butler | | |
| | |
| | |
Anne R. Pramaggiore | | |
| | |
| | |
| | |
|
| | | | | | | | | | | | | |
| By: | | /s/ DAVID M. VELAZQUEZ | | February 8, 201924, 2021 |
| Name: | | David M. Velazquez | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 8th24th day of February, 2019.
|
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| ATLANTIC CITY ELECTRIC COMPANY | |
| | |
| By: | | /s/ DAVID M. VELAZQUEZ | |
| Name: | | David M. Velazquez | |
| Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 8th24th day of February, 2019.2021.
|
| | | | | | | |
| Signature | | Title |
| |
| /s/ DAVID M. VELAZQUEZ | | President, and Chief Executive Officer (Principal Executive Officer), and Director |
| David M. Velazquez | |
| |
| /s/ PHILLIP S. BARNETT | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
|
| Phillip S. Barnett | |
| |
/s/ ROBERT M. AIKENJULIE E. GIESE | | Vice President and ControllerDirector, Accounting (Principal Accounting Officer) |
Robert M. AikenJulie E. Giese | |
| | |
/s/ CHRISTOPHER M. CRANE | | Chairman |
Christopher M. Crane | |
