false(800)(202)(410)(312)(202)(610)(215)(202)(202)--12-31Q3201910000110935710-QSeptember 30, 2020false2020Q3December 31975,572,46300011681650000022606127,021,3540000078100170,478,50700000094661,0000001135971000007973210000000278791,00000000081928,546,017PA10 South Dearborn Street500StreetP.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 Drive2 Center Plaza440 South LaSalle Street500DriveNewarkDE19702(202)872-2000NJ500 North Wakefield Drive300 Exelon WayP.O. Box 8699701 Ninth Street, N.W.701 Ninth Street, N.W.P.O. Box 805379110 West Fayette Street2301 Market StreetChicagoNewarkBaltimoreChicagoNewarkKennett SquarePhiladelphiaWashington, District of ColumbiaWashington, District of Columbia60680-53791970221201-370860605-10281970219348-247319101-86992006820068ILDEMDILDEPAPA000110935700000081920000009466000002260600000278790001168165000007810000011359710000079732PANJMDILDEVAPAPADEDCVA483-3220872-2000234-5000394-4321872-2000765-5959841-4000872-2000872-2000CommonDriveNewarkDE19702(202)872-2000Common stock, without par valueCumulativevalueEXCNasdaqEXC/28NYSECumulative Preferred Security, Series DNasdaq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years5 years30 years3 years30 years3 years30 years3 years5 years5 years30 years3 years3 years3 years4 years4 years2 years2 years14 years2 yearsP8YP1YP87YP1YP6YP1YP13YP1YP37YP1YP15YP1YP13YP1YP13YP1YP87YP1Y79 years5 years5 years1 years50 years5 years5 years5 years79 years1 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 0001109357 exc:OysterCreekMember us-gaap:OperatingExpenseMember 2019-04-01 2019-06-30 0001109357 exc:ExelonGenerationCoLLCMember exc:CommodityDerivativeAssetsMember us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember us-gaap:FairValueMeasurementsRecurringMember 2018-12-31 0001109357 exc:ExelonGenerationCoLLCMember exc:RabbiTrustInvestmentsMember us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember us-gaap:FairValueMeasurementsRecurringMember 2019-09-30 0001109357 exc:GenerationErcotMember 2019-01-01 2019-09-30 0001109357 exc:BaltimoreGasAndElectricCompanyMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityUsRegulatedMember us-gaap:RegulatedOperationMember 2019-07-01 2019-09-30D00000001.300.00000.000.0000000000000000000000000000001060981313600001109357us-gaap:RegulatedOperationMemberexc:CommonwealthEdisonCoMemberus-gaap:NaturalGasUsRegulatedMemberexc:ResidentialMember2019-01-012019-09-300001109357exc:ExelonGenerationCoLLCMemberus-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsRecurringMemberexc:OtherFixedIncomeMember2019-12-310001109357us-gaap:GuaranteeObligationsMemberexc:PotomacElectricPowerCompanyMember2020-09-30
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
|
| |
| ☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended September 30, 20192020
or
|
| |
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
|
| | | | | | | | | | | | | |
Commission File Number | | Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number | | IRS Employer Identification Number |
| | | | |
| 001-16169 | | 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
| | |
| | | | |
| 001-01839 | | 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
| | |
| | | | |
| 001-01910 | | BALTIMORE GAS AND ELECTRIC COMPANY | | 52-0280210 |
| | (a Maryland corporation)
2 Center Plaza
110 West Fayette Street
Baltimore, Maryland 21201-3708
(410) 234-5000
| | |
| | | | |
| 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
| | |
| | | | |
| 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
| | |
| | | | |
| 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 | | Trading Symbol(s) | | Name of each exchange on which registered |
EXELON CORPORATION: | | | | |
Common Stock, without par value | | EXC | | The Nasdaq Stock Market LLC |
| | | | |
| 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 |
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 x No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 x No o
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.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon Corporation | Large Accelerated Filer | x | Accelerated Filer | ☐ | Non-accelerated Filer | ☐ | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Exelon Generation Company, LLC | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Commonwealth Edison Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| PECO Energy Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Baltimore Gas and Electric Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Pepco Holdings LLC | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Potomac Electric Power Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Delmarva Power & Light Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-accelerated Filer | x | Smaller Reporting Company | ☐ | Emerging Growth Company | ☐ |
| Atlantic City Electric Company | Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | Non-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. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No x
The number of shares outstanding of each registrant’s common stock as of September 30, 20192020 was:
|
| | | | |
| Exelon Corporation Common Stock, without par value | 972,108,865975,572,463 |
| Exelon Generation Company, LLC | not applicable |
| Commonwealth Edison Company Common Stock, $12.50 par value | 127,021,343127,021,354 |
| PECO Energy Company Common Stock, without par value | 170,478,507 |
| Baltimore Gas and Electric Company Common Stock, without par value | 1,000 |
| Pepco Holdings LLC | not applicable |
| Potomac Electric Power Company Common Stock, $0.01 par value | 100 |
| Delmarva Power & Light Company Common Stock, $2.25 par value | 1,000 |
| Atlantic City Electric Company Common Stock, $3.00 par value | 8,546,017 |
TABLE OF CONTENTS
| | | | | | | | |
| 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 | |
| | |
| | |
| | |
| | |
|
| | |
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 |
| ACE Funding or ATF | | Atlantic City Electric Transition Funding LLC |
| Antelope Valley | | Antelope Valley Solar Ranch One |
| BSC | | Exelon Business Services Company, LLC |
| CENG | | Constellation Energy Nuclear Group, LLC |
| Constellation | | Constellation Energy Group, Inc. |
| EGR IV | | ExGen Renewables IV, LLC |
| EGRP | | ExGen Renewables Partners, LLC |
| Exelon Corporate | | Exelon in its corporate capacity as a holding company |
| FitzPatrick | | James A. FitzPatrick nuclear generating station |
PCINER | | NewEnergy Receivables LLC |
| PCI | | Potomac Capital Investment Corporation and its subsidiaries |
| 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 |
| SolGen | | SolGen, LLC |
| TMI | | Three Mile Island nuclear facility |
|
| | | | | | | |
| GLOSSARY OF TERMS AND ABBREVIATIONS |
| Other Terms and Abbreviations | | |
Note "—"- of the 20182019 Form 10-K | | Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 2018Exelon's 2019 Annual Report on Form 10-K |
AESOAEC | | 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 |
AMI | | |
| AMI | | Advanced Metering Infrastructure |
AOCI | | |
| AOCI | | Accumulated Other Comprehensive Income (Loss) |
| ARC | | Asset Retirement Cost |
| ARO | | Asset Retirement Obligation |
BGS | | |
| BGS | | Basic Generation Service |
CERCLA | | |
| | |
| | |
| | |
| CBA | | Collective Bargaining Agreement
|
| 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 |
| CODM | | Chief operating decision maker(s) |
| | |
| | |
| | |
| | |
| 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 | | Public Service Commission of the District of Columbia |
DOE | | |
| DOE | | United States Department of Energy |
| DOEE | | District of Columbia Department of Energy & Environment |
| DOJ | | United States Department of Justice |
DPSCDPP | | Deferred Purchase Price |
| DPSC | | Delaware Public Service Commission |
EDF | | |
| | |
| | |
| EDF | | Electricite de France SA and its subsidiaries |
EIMA | | |
| EIMA | | Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036) |
EPA | | |
| EPA | | United States Environmental Protection Agency |
EPSA | | Electric Power Supply Association |
| ERCOT | | Electric Reliability Council of Texas |
FASB | | |
| | |
| | |
| 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 |
GSA | | |
| GSA | | Generation Supply Adjustment |
ICC | | Illinois Commerce Commission |
ICE | | Intercontinental Exchange |
Illinois EPA | | Illinois Environmental Protection Agency |
IPA | | Illinois Power Agency |
IRC | | Internal Revenue Code |
IRS | | Internal Revenue Service |
|
| | |
| IBEW | | International Brotherhood of Electrical Workers
|
| ICC | | Illinois Commerce Commission |
| ICE | | Intercontinental Exchange |
| | |
| | |
| | |
| IPA | | Illinois Power Agency |
| IRC | | Internal Revenue Code |
| IRS | | Internal Revenue Service |
| | | | | | | | |
| GLOSSARY OF TERMS AND ABBREVIATIONS |
| Other Terms and Abbreviations | | |
| ISO | | Independent System Operator |
| ISO-NE | | Independent System Operator New England Inc. |
ISO-NY | | Independent System Operator New York |
LIBOR | | |
| | |
| | |
| LIBOR | | London Interbank Offered Rate |
MDE | | |
| | |
| | |
| | |
| | |
| | |
| | |
| 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 |
MOPR | | |
| MOPR | | Minimum Offer Price Rule |
MW | | Megawatt |
NAAQSMW | | National Ambient Air Quality StandardsMegawatt |
NDTMWh | | Megawatt hour |
| | |
| | |
| | |
| NDT | | Nuclear Decommissioning Trust |
NEIL | | Nuclear Electric Insurance Limited |
| NERC | | North American Electric Reliability Corporation |
NJBPUNGX | | Natural Gas Exchange |
| NJBPU | | New Jersey Board of Public Utilities |
| | |
| | |
Non-Regulatory AgreementsAgreement 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 |
NPNS | | |
| NPNS | | Normal Purchase Normal Sale scope exception |
| NRC | | Nuclear Regulatory Commission |
NYMEX | | |
| | |
| | |
| NYISO | | New York Independent System Operator Inc. |
| NYMEX | | New York Mercantile Exchange |
| NYPSC | | New York Public Service Commission |
| OCI | | Other Comprehensive Income |
| OIESO | | Ontario Independent Electricity System Operator |
OPEB | | |
| OPEB | | Other Postretirement Employee Benefits |
Oyster Creek | | Oyster Creek Generating Station |
PA DEP | | Pennsylvania Department of Environmental Protection |
| PAPUC | | Pennsylvania Public Utility Commission |
PGC | | |
| PGC | | Purchased Gas Cost Clause |
| PG&E | | Pacific Gas and Electric Company |
| PJM | | PJM Interconnection, LLC |
| POLR | | Provider of Last Resort |
PPA | | |
| PPA | | Power Purchase Agreement |
| PPE | | Property, plant, and equipment |
| Price-Anderson Act | | Price-Anderson Nuclear Industries Indemnity Act of 1957 |
PRP | | |
| PRP | | Potentially Responsible Parties |
| PSDAR | | Post-Shutdown Decommissioning Activities Report |
| PSEG | | Public Service Enterprise Group Incorporated |
REC | | |
| | |
| REC | | Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source |
| RNF | | Revenues Net of Purchased Power and Fuel Expense |
|
| | |
GLOSSARY OF TERMS AND ABBREVIATIONS |
Other Terms and Abbreviations | | |
| Regulatory Agreement Units | | Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting |
Rider | | |
| RFP | | Request for Proposal |
| Rider | | Reconcilable Surcharge Recovery Mechanism |
| RMC | | Risk Management Committee |
| ROE | | Return on equity |
| | | | | | | | |
ROU | | Right-of-useGLOSSARY OF TERMS AND ABBREVIATIONS |
RSSAOther Terms and Abbreviations | | Reliability Support Services Agreement |
RTOROU | | Right-of-use |
| | |
| | |
| | |
| | |
| RTO | | Regional Transmission Organization |
SECS&P | | Standard & Poor’s Ratings Services |
| SEC | | United States Securities and Exchange Commission |
SERC | | |
| SEIU | | Service Employees International Union |
| SERC | | SERC Reliability Corporation (formerly Southeast Electric Reliability Council) |
SNF | | |
| SNF | | Spent Nuclear Fuel |
| SOS | | Standard Offer Service |
TCJA | | |
| | |
| SPFPA | | International Union, Security, Police, and Fire Professionals of America
|
| STRIDE | | Maryland Strategic Infrastructure Development and Enhancement Program |
| TCJA | | Tax Cuts and Jobs Act |
| | |
| Transition Bonds | | Transition Bonds issued by ACE Funding |
Upstream | | Natural gas exploration and production activities |
VIEUGSOA | | United Government Security Officers of America |
| VIE | | Variable Interest Entity |
| WECC | | Western Electric Coordinating Council |
| ZEC | | Zero Emission Credit, or Zero Emission Certificate |
| ZES | | Zero Emission Standard |
FILING FORMAT
This combined Form 10-Q 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 including among others those related to the expected or potential impact of the novel coronavirus (COVID-19) pandemic, and the related responses of various governments and regulatory bodies, our customers, and the company, on our business, financial condition and results of operations; any such forward-looking statements, whether concerning the COVID-19 pandemic or otherwise, involve risks, assumptions and uncertainties. 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, as well as the items discussed in (1) the Registrants' combined 20182019 Annual Report on Form 10-K 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 22,18, Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors;Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 16,14, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants. Readers
Investors are cautioned not to place undue reliance on these forward-looking statements, whether written or oral, 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. FINANCIAL INFORMATION
Item 1. Financial Statements
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
| | | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions, except per share data) | 2019 | | 2018 | | 2019 | | 2018 | (In millions, except per share data) | 2020 | | 2019 | | 2020 | | 2019 |
| Operating revenues | | | | | | | | Operating revenues | | | | | | | |
| Competitive businesses revenues | $ | 4,499 |
| | $ | 4,971 |
| | $ | 13,436 |
| | $ | 14,387 |
| Competitive businesses revenues | $ | 4,330 | | | $ | 4,499 | | | $ | 12,344 | | | $ | 13,436 | |
| Rate-regulated utility revenues | 4,510 |
| | 4,457 |
| | 12,758 |
| | 12,824 |
| Rate-regulated utility revenues | 4,533 | | | 4,510 | | | 12,643 | | | 12,758 | |
| Revenues from alternative revenue programs | (80 | ) | | (25 | ) | | (98 | ) | | (41 | ) | Revenues from alternative revenue programs | (11) | | | (80) | | | (66) | | | (98) | |
| Operating revenue from affiliates | | Operating revenue from affiliates | 1 | | | 0 | | | 4 | | | 0 | |
| Total operating revenues | 8,929 |
| | 9,403 |
| | 26,096 |
| | 27,170 |
| Total operating revenues | 8,853 | | | 8,929 | | | 24,925 | | | 26,096 | |
| Operating expenses | | | | | | | | Operating expenses | | | | | | | |
| Competitive businesses purchased power and fuel | 2,648 |
| | 2,977 |
| | 8,142 |
| | 8,542 |
| Competitive businesses purchased power and fuel | 2,311 | | | 2,648 | | | 6,967 | | | 8,142 | |
| Rate-regulated utility purchased power and fuel | 1,304 |
| | 1,355 |
| | 3,589 |
| | 3,832 |
| Rate-regulated utility purchased power and fuel | 1,303 | | | 1,304 | | | 3,439 | | | 3,589 | |
| | Operating and maintenance | 2,072 |
| | 2,346 |
| | 6,419 |
| | 7,036 |
| Operating and maintenance | 2,732 | | | 2,072 | | | 7,370 | | | 6,419 | |
| Depreciation and amortization | 1,083 |
| | 1,105 |
| | 3,237 |
| | 3,284 |
| Depreciation and amortization | 1,289 | | | 1,083 | | | 3,312 | | | 3,237 | |
| Taxes other than income | 452 |
| | 469 |
| | 1,316 |
| | 1,342 |
| |
| Taxes other than income taxes | | Taxes other than income taxes | 452 | | | 452 | | | 1,299 | | | 1,316 | |
| Total operating expenses | 7,559 |
|
| 8,252 |
|
| 22,703 |
|
| 24,036 |
| Total operating expenses | 8,087 | | | 7,559 | | | 22,387 | | | 22,703 | |
| (Loss) gain on sales of assets and businesses | (17 | ) | | (5 | ) | | 19 |
| | 55 |
| |
| | Gain (Loss) on sales of assets and businesses | | Gain (Loss) on sales of assets and businesses | 3 | | | (17) | | | 16 | | | 19 | |
| | Operating income | 1,353 |
|
| 1,146 |
|
| 3,412 |
|
| 3,189 |
| Operating income | 769 | | | 1,353 | | | 2,554 | | | 3,412 | |
| Other income and (deductions) | | | | |
| |
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (403 | ) | | (387 | ) | | (1,202 | ) | | (1,119 | ) | Interest expense, net | (398) | | | (403) | | | (1,222) | | | (1,202) | |
| Interest expense to affiliates | (6 | ) | | (6 | ) | | (19 | ) | | (19 | ) | Interest expense to affiliates | (6) | | | (6) | | | (19) | | | (19) | |
| Other, net | 158 |
| | 194 |
| | 837 |
| | 212 |
| Other, net | 421 | | | 158 | | | 352 | | | 837 | |
| Total other income and (deductions) | (251 | ) |
| (199 | ) |
| (384 | ) |
| (926 | ) | Total other income and (deductions) | 17 | | | (251) | | | (889) | | | (384) | |
| Income before income taxes | 1,102 |
| | 947 |
| | 3,028 |
| | 2,263 |
| Income before income taxes | 786 | | | 1,102 | | | 1,665 | | | 3,028 | |
| Income taxes | 172 |
| | 137 |
| | 626 |
| | 262 |
| Income taxes | 216 | | | 172 | | | 141 | | | 626 | |
| Equity in losses of unconsolidated affiliates | (170 | ) | | (10 | ) | | (182 | ) | | (22 | ) | Equity in losses of unconsolidated affiliates | (1) | | | (170) | | | (5) | | | (182) | |
| Net income | 760 |
|
| 800 |
|
| 2,220 |
|
| 1,979 |
| Net income | 569 | | | 760 | | | 1,519 | | | 2,220 | |
| Net (loss) income attributable to noncontrolling interests | (12 | ) | | 67 |
| | 56 |
| | 121 |
| |
| Net income (loss) attributable to noncontrolling interests | | Net income (loss) attributable to noncontrolling interests | 68 | | | (12) | | | (85) | | | 56 | |
| Net income attributable to common shareholders | $ | 772 |
|
| $ | 733 |
|
| $ | 2,164 |
|
| $ | 1,858 |
| Net income attributable to common shareholders | $ | 501 | | | $ | 772 | | | $ | 1,604 | | | $ | 2,164 | |
| Comprehensive income, net of income taxes | | | | | | | | Comprehensive income, net of income taxes | | | | | | | |
| Net income | $ | 760 |
| | $ | 800 |
| | $ | 2,220 |
| | $ | 1,979 |
| Net income | $ | 569 | | | $ | 760 | | | $ | 1,519 | | | $ | 2,220 | |
| 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 | (16 | ) | | (17 | ) | | (49 | ) | | (50 | ) | Prior service benefit reclassified to periodic benefit cost | (10) | | | (16) | | | (30) | | | (49) | |
| Actuarial loss reclassified to periodic benefit cost | 37 |
| | 62 |
| | 111 |
| | 186 |
| Actuarial loss reclassified to periodic benefit cost | 49 | | | 37 | | | 142 | | | 111 | |
| Pension and non-pension postretirement benefit plan valuation adjustment | 6 |
| | 5 |
| | (32 | ) | | 22 |
| Pension and non-pension postretirement benefit plan valuation adjustment | (13) | | | 6 | | | (17) | | | (32) | |
| Unrealized gain on cash flow hedges | — |
| | — |
| | — |
| | 12 |
| |
| Unrealized loss on cash flow hedges | | Unrealized loss on cash flow hedges | (1) | | | 0 | | | (2) | | | 0 | |
| Unrealized gain on investments in unconsolidated affiliates | 5 |
| | — |
| | 1 |
| | 3 |
| Unrealized gain on investments in unconsolidated affiliates | 0 | | | 5 | | | 0 | | | 1 | |
| Unrealized (loss) gain on foreign currency translation | (2 | ) | | 2 |
| | 2 |
| | (4 | ) | |
| Unrealized gain (loss) on foreign currency translation | | Unrealized gain (loss) on foreign currency translation | 3 | | | (2) | | | (3) | | | 2 | |
| | Other comprehensive income | 30 |
|
| 52 |
|
| 33 |
|
| 169 |
| Other comprehensive income | 28 | | | 30 | | | 90 | | | 33 | |
| Comprehensive income | 790 |
|
| 852 |
|
| 2,253 |
|
| 2,148 |
| Comprehensive income | 597 | | | 790 | | | 1,609 | | | 2,253 | |
| Comprehensive (loss) income attributable to noncontrolling interests | (9 | ) | | 67 |
| | 57 |
| | 123 |
| |
| Comprehensive income (loss) attributable to noncontrolling interests | | Comprehensive income (loss) attributable to noncontrolling interests | 68 | | | (9) | | | (85) | | | 57 | |
| Comprehensive income attributable to common shareholders | $ | 799 |
| | $ | 785 |
| | $ | 2,196 |
| | $ | 2,025 |
| Comprehensive income attributable to common shareholders | $ | 529 | | | $ | 799 | | | $ | 1,694 | | | $ | 2,196 | |
| | | | | | | | | | | | | | | | |
| Average shares of common stock outstanding: | | | | | | | | Average shares of common stock outstanding: | |
| Basic | 973 |
| | 968 |
| | 972 |
| | 967 |
| Basic | 976 | | | 973 | | | 976 | | | 972 | |
| Assumed exercise and/or distributions of stock-based awards | 1 |
| | 2 |
| | 1 |
| | 2 |
| Assumed exercise and/or distributions of stock-based awards | 1 | | | 1 | | | 0 | | | 1 | |
Diluted(a) | 974 |
| | 970 |
| | 973 |
| | 969 |
| Diluted(a) | 977 | | | 974 | | | 976 | | | 973 | |
| | | | | | | | | | | | | | | | |
| Earnings per average common share: | | | | | | | | Earnings per average common share: | |
| Basic | $ | 0.79 |
| | $ | 0.76 |
| | $ | 2.23 |
| | $ | 1.92 |
| Basic | $ | 0.51 | | | $ | 0.79 | | | $ | 1.64 | | | $ | 2.23 | |
| Diluted | $ | 0.79 |
| | $ | 0.76 |
| | $ | 2.22 |
| | $ | 1.92 |
| Diluted | $ | 0.51 | | | $ | 0.79 | | | $ | 1.64 | | | $ | 2.22 | |
__________
| |
(a) | The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was immaterial for the three and nine months ended September 30, 2019 and approximately 2 million and 3 million for the three and nine months ended September 30, 2018, respectively. |
(a)The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 1 million for the three and nine months ended September 30, 2020, and less than 1 million for the three and nine months ended September 30, 2019.
See the Combined Notes to Consolidated Financial Statements
10
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | |
| Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 |
| Cash flows from operating activities | | | |
| Net income | $ | 1,519 | | | $ | 2,220 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | 4,419 | | | 4,393 | |
| Asset impairments | 567 | | | 174 | |
| | | |
| Gain on sales of assets and businesses | (16) | | | (15) | |
| | | |
| Deferred income taxes and amortization of investment tax credits | 164 | | | 412 | |
| Net fair value changes related to derivatives | (448) | | | 96 | |
| Net realized and unrealized gains on NDT funds | (59) | | | (467) | |
| Other non-cash operating activities | 988 | | | 460 | |
| Changes in assets and liabilities: | | | |
| Accounts receivable | 1,195 | | | 445 | |
| Inventories | (67) | | | (94) | |
| Accounts payable and accrued expenses | (519) | | | (671) | |
| Option premiums (paid) received, net | (131) | | | 13 | |
| Collateral received (posted), net | 644 | | | (254) | |
| Income taxes | (31) | | | 143 | |
| Pension and non-pension postretirement benefit contributions | (580) | | | (377) | |
| Other assets and liabilities | (3,423) | | | (1,079) | |
| Net cash flows provided by operating activities | 4,222 | | | 5,399 | |
| Cash flows from investing activities | | | |
| Capital expenditures | (5,606) | | | (5,259) | |
| Proceeds from NDT fund sales | 3,370 | | | 8,443 | |
| Investment in NDT funds | (3,438) | | | (8,437) | |
| Collection of DPP | 2,518 | | | 0 | |
| | | |
| Proceeds from sales of assets and businesses | 46 | | | 17 | |
| | | |
| | | |
| Other investing activities | (2) | | | 21 | |
| Net cash flows used in investing activities | (3,112) | | | (5,215) | |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | (689) | | | 430 | |
| Proceeds from short-term borrowings with maturities greater than 90 days | 500 | | | 0 | |
| Repayments on short-term borrowings with maturities greater than 90 days | 0 | | | (125) | |
| Issuance of long-term debt | 6,756 | | | 1,576 | |
| Retirement of long-term debt | (5,158) | | | (644) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Dividends paid on common stock | (1,119) | | | (1,055) | |
| | | |
| Proceeds from employee stock plans | 62 | | | 94 | |
| Other financing activities | (104) | | | (63) | |
| Net cash flows provided by financing activities | 248 | | | 213 | |
| Increase in cash, cash equivalents, and restricted cash | 1,358 | | | 397 | |
| Cash, cash equivalents, and restricted cash at beginning of period | 1,122 | | | 1,781 | |
| Cash, cash equivalents, and restricted cash at end of period | $ | 2,480 | | | $ | 2,178 | |
| | | |
| Supplemental cash flow information | | | |
| Decrease in capital expenditures not paid | $ | (11) | | | $ | (96) | |
| Increase in DPP | 3,275 | | | 0 | |
| Increase in PPE related to ARO update | 775 | | | 344 | |
See the Combined Notes to Consolidated Financial Statements
11
|
| | | | | | | |
| | Nine Months Ended
September 30, |
| (In millions) | 2019 | | 2018 |
| Cash flows from operating activities | | | |
| Net income | $ | 2,220 |
| | $ | 1,979 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization | 4,393 |
| | 4,511 |
|
| Asset impairments | 174 |
| | 49 |
|
| Gain on sales of assets and businesses | (15 | ) | | (55 | ) |
| Deferred income taxes and amortization of investment tax credits | 412 |
| | 97 |
|
| Net fair value changes related to derivatives | 96 |
| | 67 |
|
| Net realized and unrealized gains on NDT funds | (467 | ) | | (21 | ) |
| Other non-cash operating activities | 460 |
| | 804 |
|
| Changes in assets and liabilities: | | | |
| Accounts receivable | 445 |
| | (167 | ) |
| Inventories | (94 | ) | | (24 | ) |
| Accounts payable and accrued expenses | (671 | ) | | 84 |
|
| Option premiums received (paid), net | 13 |
| | (36 | ) |
| Collateral (posted) received, net | (254 | ) | | 222 |
|
| Income taxes | 143 |
| | 166 |
|
| Pension and non-pension postretirement benefit contributions | (377 | ) | | (362 | ) |
| Other assets and liabilities | (1,079 | ) | | (639 | ) |
| Net cash flows provided by operating activities | 5,399 |
|
| 6,675 |
|
| Cash flows from investing activities | | | |
| Capital expenditures | (5,259 | ) | | (5,497 | ) |
| Proceeds from NDT fund sales | 8,443 |
| | 6,379 |
|
| Investment in NDT funds | (8,437 | ) | | (6,553 | ) |
| Acquisition of assets and businesses, net | — |
| | (57 | ) |
| Proceeds from sales of assets and businesses | 17 |
| | 90 |
|
| Other investing activities | 21 |
| | 29 |
|
| Net cash flows used in investing activities | (5,215 | ) |
| (5,609 | ) |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | 430 |
| | (218 | ) |
| Proceeds from short-term borrowings with maturities greater than 90 days | — |
| | 126 |
|
| Repayments on short-term borrowings with maturities greater than 90 days | (125 | ) | | (1 | ) |
| Issuance of long-term debt | 1,576 |
| | 2,664 |
|
| Retirement of long-term debt | (644 | ) | | (1,480 | ) |
| Dividends paid on common stock | (1,055 | ) | | (999 | ) |
| Proceeds from employee stock plans | 94 |
| | 67 |
|
| Other financing activities | (63 | ) | | (94 | ) |
| Net cash flows provided by financing activities | 213 |
|
| 65 |
|
| Increase in cash, cash equivalents and restricted cash | 397 |
| | 1,131 |
|
| Cash, cash equivalents and restricted cash at beginning of period | 1,781 |
| | 1,190 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 2,178 |
|
| $ | 2,321 |
|
| | | | |
| Supplemental cash flow information | | | |
| Decrease in capital expenditures not paid | $ | (96 | ) | | $ | (175 | ) |
| Increase in PPE related to ARO update | 344 |
| | 67 |
|
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 1,858 | | | $ | 587 | |
| Restricted cash and cash equivalents | 485 | | | 358 | |
| | | |
| Accounts receivable | | | |
| Customer accounts receivable | 3,150 | | 4,835 |
| Customer allowance for credit losses | (358) | | (243) |
| Customer accounts receivable, net | 2,792 | | | 4,592 | |
| Other accounts receivable | 1,576 | | 1,631 |
| Other allowance for credit losses | (75) | | (48) |
| Other accounts receivable, net | 1,501 | | | 1,583 | |
| Mark-to-market derivative assets | 472 | | | 679 | |
| Unamortized energy contract assets | 41 | | | 47 | |
| Inventories, net | | | |
| Fossil fuel and emission allowances | 311 | | | 312 | |
| Materials and supplies | 1,405 | | | 1,456 | |
| Regulatory assets | 1,170 | | | 1,170 | |
| | | |
| Other | 2,277 | | | 1,253 | |
| Total current assets | 12,312 | | | 12,037 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $25,582 and $23,979 as of September 30, 2020 and December 31, 2019, respectively) | 82,561 | | | 80,233 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 8,485 | | | 8,335 | |
| Nuclear decommissioning trust funds | 13,432 | | | 13,190 | |
| Investments | 444 | | | 464 | |
| Goodwill | 6,677 | | | 6,677 | |
| Mark-to-market derivative assets | 383 | | | 508 | |
| Unamortized energy contract assets | 308 | | | 336 | |
| | | |
| Other | 3,165 | | | 3,197 | |
| Total deferred debits and other assets | 32,894 | | | 32,707 | |
Total assets(a) | $ | 127,767 | | | $ | 124,977 | |
See the Combined Notes to Consolidated Financial Statements
12
|
| | | | | | | |
| (In millions) | September 30, 2019 | | December 31, 2018 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 1,683 |
| | $ | 1,349 |
|
| Restricted cash and cash equivalents | 309 |
| | 247 |
|
| Accounts receivable, net | | | |
| Customer (net of allowance for uncollectible accounts of $248 and $283 as of September 30, 2019 and December 31, 2018, respectively) | 4,188 |
| | 4,607 |
|
| Other (net of allowance for uncollectible accounts of $49 and $36 as of September 30, 2019 and December 31, 2018, respectively) | 1,085 |
| | 1,256 |
|
| Mark-to-market derivative assets | 601 |
| | 804 |
|
| Unamortized energy contract assets | 49 |
| | 48 |
|
| Inventories, net | | | |
| Fossil fuel and emission allowances | 325 |
| | 334 |
|
| Materials and supplies | 1,458 |
| | 1,351 |
|
| Regulatory assets | 1,194 |
| | 1,222 |
|
| Assets held for sale | 18 |
| | 904 |
|
| Other | 1,296 |
| | 1,238 |
|
| Total current assets | 12,206 |
|
| 13,360 |
|
| Property, plant and equipment (net of accumulated depreciation and amortization of $23,590 and $22,902 as of September 30, 2019 and December 31, 2018, respectively) | 78,593 |
| | 76,707 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 8,122 |
| | 8,237 |
|
| Nuclear decommissioning trust funds | 12,706 |
| | 11,661 |
|
| Investments | 471 |
| | 625 |
|
| Goodwill | 6,677 |
| | 6,677 |
|
| Mark-to-market derivative assets | 487 |
| | 452 |
|
| Unamortized energy contract assets | 353 |
| | 372 |
|
| Other | 3,123 |
| | 1,575 |
|
| Total deferred debits and other assets | 31,939 |
|
| 29,599 |
|
Total assets(a) | $ | 122,738 |
|
| $ | 119,666 |
|
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | (In millions) | September 30, 2019 | | December 31, 2018 | (In millions) | September 30, 2020 | | December 31, 2019 |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities | | | | Current liabilities | |
| Short-term borrowings | $ | 1,019 |
| | $ | 714 |
| Short-term borrowings | $ | 1,181 | | | $ | 1,370 | |
| Long-term debt due within one year | 4,248 |
| | 1,349 |
| Long-term debt due within one year | 2,077 | | | 4,710 | |
| Accounts payable | 3,348 |
| | 3,800 |
| Accounts payable | 3,182 | | | 3,560 | |
| Accrued expenses | 1,877 |
| | 2,112 |
| Accrued expenses | 1,879 | | | 1,981 | |
| Payables to affiliates | 5 |
| | 5 |
| Payables to affiliates | 5 | | | 5 | |
| Regulatory liabilities | 400 |
| | 644 |
| Regulatory liabilities | 575 | | | 406 | |
| Mark-to-market derivative liabilities | 239 |
| | 475 |
| Mark-to-market derivative liabilities | 177 | | | 247 | |
| Unamortized energy contract liabilities | 138 |
| | 149 |
| Unamortized energy contract liabilities | 107 | | | 132 | |
| Renewable energy credit obligation | 375 |
| | 344 |
| Renewable energy credit obligation | 604 | | | 443 | |
| Liabilities held for sale | 11 |
| | 777 |
| |
| | Other | 1,425 |
| | 1,035 |
| Other | 1,475 | | | 1,331 | |
| Total current liabilities | 13,085 |
| | 11,404 |
| Total current liabilities | 11,262 | | | 14,185 | |
| Long-term debt | 32,056 |
| | 34,075 |
| Long-term debt | 35,512 | | | 31,329 | |
| Long-term debt to financing trusts | 390 |
| | 390 |
| 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 | 12,133 |
| | 11,330 |
| Deferred income taxes and unamortized investment tax credits | 13,058 | | | 12,351 | |
| Asset retirement obligations | 10,089 |
| | 9,679 |
| Asset retirement obligations | 11,989 | | | 10,846 | |
| Pension obligations | 3,712 |
| | 3,988 |
| Pension obligations | 3,648 | | | 4,247 | |
| Non-pension postretirement benefit obligations | 2,029 |
| | 1,928 |
| Non-pension postretirement benefit obligations | 2,128 | | | 2,076 | |
| Spent nuclear fuel obligation | 1,193 |
| | 1,171 |
| Spent nuclear fuel obligation | 1,207 | | | 1,199 | |
| Regulatory liabilities | 9,792 |
| | 9,559 |
| Regulatory liabilities | 9,495 | | | 9,986 | |
| Mark-to-market derivative liabilities | 416 |
| | 479 |
| Mark-to-market derivative liabilities | 396 | | | 393 | |
| Unamortized energy contract liabilities | 368 |
| | 463 |
| Unamortized energy contract liabilities | 266 | | | 338 | |
| | Other | 3,123 |
| | 2,130 |
| Other | 3,313 | | | 3,064 | |
| Total deferred credits and other liabilities | 42,855 |
| | 40,727 |
| Total deferred credits and other liabilities | 45,500 | | | 44,500 | |
Total liabilities(a) | 88,386 |
|
| 86,596 |
| Total liabilities(a) | 92,664 | | | 90,404 | |
| Commitments and contingencies |
| |
| Commitments and contingencies | | | |
| | Shareholders’ equity | | | | Shareholders’ equity | |
| Common stock (No par value, 2,000 shares authorized, 972 shares and 968 shares outstanding at September 30, 2019 and December 31, 2018, respectively) | 19,238 |
| | 19,116 |
| |
| Treasury stock, at cost (2 shares at September 30, 2019 and December 31, 2018) | (123 | ) | | (123 | ) | |
| Common stock (No par value, 2,000 shares authorized, 976 shares and 973 shares outstanding at September 30, 2020 and December 31, 2019, respectively) | | Common stock (No par value, 2,000 shares authorized, 976 shares and 973 shares outstanding at September 30, 2020 and December 31, 2019, respectively) | 19,362 | | | 19,274 | |
| Treasury stock, at cost (2 shares at September 30, 2020 and December 31, 2019) | | Treasury stock, at cost (2 shares at September 30, 2020 and December 31, 2019) | (123) | | | (123) | |
| Retained earnings | 15,871 |
| | 14,766 |
| Retained earnings | 16,749 | | | 16,267 | |
| Accumulated other comprehensive loss, net | (2,963 | ) | | (2,995 | ) | Accumulated other comprehensive loss, net | (3,104) | | | (3,194) | |
| Total shareholders’ equity | 32,023 |
|
| 30,764 |
| Total shareholders’ equity | 32,884 | | | 32,224 | |
| Noncontrolling interests | 2,329 |
| | 2,306 |
| Noncontrolling interests | 2,219 | | | 2,349 | |
| Total equity | 34,352 |
|
| 33,070 |
| Total equity | 35,103 | | | 34,573 | |
| Total liabilities and shareholders’ equity | $ | 122,738 |
|
| $ | 119,666 |
| Total liabilities and shareholders’ equity | $ | 127,767 | | | $ | 124,977 | |
__________
| |
(a) | Exelon’s consolidated assets include $9,465 million and $9,667 million at September 30, 2019 and December 31, 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,517 million and $3,548 million at September 30, 2019 and December 31, 2018, 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 $10,102 million and $9,532 million at September 30, 2020 and December 31, 2019, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,531 million and $3,473 million at September 30, 2020 and December 31, 2019, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 16 — Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
13
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
(In millions, shares
in thousands) | Issued
Shares | | Common
Stock | | Treasury
Stock | | Retained
Earnings | | Accumulated
Other
Comprehensive
Loss, net | | Noncontrolling
Interests | | Total Shareholders'
Equity |
| Balance, December 31, 2019 | 974,416 | | | $ | 19,274 | | | $ | (123) | | | $ | 16,267 | | | $ | (3,194) | | | $ | 2,349 | | | $ | 34,573 | |
| Net income (loss) | — | | | — | | | — | | | 582 | | | — | | | (206) | | | 376 | |
| Long-term incentive plan activity | 1,354 | | | (4) | | | 0 | | | 0 | | | 0 | | | 0 | | | (4) | |
| Employee stock purchase plan issuances | 470 | | | 31 | | | 0 | | | 0 | | | 0 | | | 0 | | | 31 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (9) | | | (9) | |
| Sale of noncontrolling interests | — | | | 2 | | | — | | | — | | | — | | | — | | | 2 | |
Common stock dividends ($0.38/common share) | — | | | — | | | — | | | (374) | | | — | | | — | | | (374) | |
| Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 21 | | | 0 | | | 21 | |
| | | | | | | | | | | | | |
| Balance, March 31, 2020 | 976,240 | | | $ | 19,303 | | | $ | (123) | | | $ | 16,475 | | | $ | (3,173) | | | $ | 2,134 | | | $ | 34,616 | |
| Net income | — | | | — | | | — | | | 521 | | | — | | | 53 | | | 574 | |
| Long-term incentive plan activity | 148 | | | 17 | | | 0 | | | 0 | | | 0 | | | 0 | | | 17 | |
| Employee stock purchase plan issuances | (51) | | | 15 | | | 0 | | | 0 | | | 0 | | | 0 | | | 15 | |
| | | | | | | | | | | | | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (19) | | | (19) | |
| Sale of noncontrolling interests | — | | | 1 | | | — | | | — | | | — | | | — | | | 1 | |
| | | | | | | | | | | | | |
Common stock dividends ($0.38/common share) | — | | | — | | | — | | | (374) | | | — | | | — | | | (374) | |
| Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 41 | | | 0 | | | 41 | |
| | | | | | | | | | | | | |
| Balance, June 30, 2020 | 976,337 | | | $ | 19,336 | | | $ | (123) | | | $ | 16,622 | | | $ | (3,132) | | | $ | 2,168 | | | $ | 34,871 | |
| Net income | — | | | — | | | — | | | 501 | | | — | | | 68 | | | 569 | |
| Long-term incentive plan activity | 68 | | | 10 | | | — | | | — | | | — | | | — | | | 10 | |
| Employee stock purchase plan issuances | 1,000 | | | 16 | | | — | | | — | | | — | | | — | | | 16 | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (17) | | | (17) | |
| | | | | | | | | | | | | |
Common stock dividends ($0.38/common share) | — | | | — | | | — | | | (374) | | | — | | | — | | | (374) | |
| Other comprehensive income net of income taxes | — | | | — | | | — | | | — | | | 28 | | | — | | | 28 | |
| Balance, September 30, 2020 | 977,405 | | | $ | 19,362 | | | $ | (123) | | | $ | 16,749 | | | $ | (3,104) | | | $ | 2,219 | | | $ | 35,103 | |
See the Combined Notes to Consolidated Financial Statements
14
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 |
(In millions, shares in thousands) | Issued Shares | | Common Stock | | Treasury Stock | | Retained Earnings | | Accumulated Other Comprehensive Loss, net | | Noncontrolling Interests | | Total Shareholders' Equity |
| Balance, December 31, 2018 | 970,020 |
| | $ | 19,116 |
| | $ | (123 | ) | | $ | 14,766 |
| | $ | (2,995 | ) | | $ | 2,306 |
| | $ | 33,070 |
|
| Net income | — |
| | — |
| | — |
| | 907 |
| | — |
| | 59 |
| | 966 |
|
| Long-term incentive plan activity | 2,446 |
| | (3 | ) | | — |
| | — |
| | — |
| | — |
| | (3 | ) |
| Employee stock purchase plan issuances | 320 |
| | 51 |
| | — |
| | — |
| | — |
| | — |
| | 51 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (17 | ) | | (17 | ) |
| Sale of noncontrolling interests | — |
| | 7 |
| | — |
| | — |
| | — |
| | — |
| | 7 |
|
Common stock dividends ($0.36/common share) | — |
| | — |
| | — |
| | (352 | ) | | — |
| | — |
| | (352 | ) |
| Other comprehensive loss, net of income taxes | — |
| | — |
| | — |
| | — |
| | (17 | ) | | (1 | ) | | (18 | ) |
| Balance, March 31, 2019 | 972,786 |
|
| $ | 19,171 |
|
| $ | (123 | ) |
| $ | 15,321 |
|
| $ | (3,012 | ) |
| $ | 2,347 |
|
| $ | 33,704 |
|
| Net income | — |
| | — |
| | — |
| | 484 |
| | — |
| | 10 |
| | 494 |
|
| Long-term incentive plan activity | 320 |
| | 14 |
| | — |
| | — |
| | — |
| | — |
| | 14 |
|
| Employee stock purchase plan issuances | 311 |
| | 24 |
| | — |
| | — |
| | — |
| | — |
| | 24 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
| | 3 |
|
Common stock dividends
($0.36/common share) | — |
| | — |
| | — |
| | (353 | ) | | — |
| | — |
| | (353 | ) |
| Other comprehensive income (loss), net of income taxes | — |
| | — |
| | — |
| | — |
| | 22 |
| | (1 | ) | | 21 |
|
| Balance, June 30, 2019 | 973,417 |
| | $ | 19,209 |
| | $ | (123 | ) | | $ | 15,452 |
| | $ | (2,990 | ) | | $ | 2,359 |
| | $ | 33,907 |
|
| Net income (loss) | — |
| | — |
| | — |
| | 772 |
| | — |
| | (12 | ) | | 760 |
|
| Long-term incentive plan activity | 207 |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | 10 |
|
| Employee stock purchase plan issuances | 317 |
| | 19 |
| | — |
| | — |
| | — |
| | — |
| | 19 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (18 | ) | | (18 | ) |
Common stock dividends
($0.36/common share) | — |
| | — |
| | — |
| | (353 | ) | | — |
| | — |
| | (353 | ) |
| Other comprehensive income net of income taxes | — |
| | — |
| | — |
| | — |
| | 27 |
| | — |
| | 27 |
|
| Balance, September 30, 2019 | 973,941 |
| | $ | 19,238 |
| | $ | (123 | ) | | $ | 15,871 |
| | $ | (2,963 | ) | | $ | 2,329 |
| | $ | 34,352 |
|
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 |
(In millions, shares
in thousands) | Issued
Shares | | Common
Stock | | Treasury
Stock | | Retained
Earnings | | Accumulated
Other
Comprehensive
Loss, net | | Noncontrolling
Interests | | Total Shareholders'
Equity |
| Balance, December 31, 2018 | 970,020 | | | $ | 19,116 | | | $ | (123) | | | $ | 14,766 | | | $ | (2,995) | | | $ | 2,306 | | | $ | 33,070 | |
| Net income | — | | | — | | | — | | | 907 | | | — | | | 59 | | | 966 | |
| Long-term incentive plan activity | 2,446 | | | (3) | | | 0 | | | 0 | | | 0 | | | 0 | | | (3) | |
| Employee stock purchase plan issuances | 320 | | | 51 | | | 0 | | | 0 | | | 0 | | | 0 | | | 51 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (17) | | | (17) | |
| Sale of noncontrolling interests | — | | | 7 | | | — | | | — | | | — | | | — | | | 7 | |
Common stock dividends ($0.36/common share) | — | | | — | | | — | | | (352) | | | — | | | — | | | (352) | |
| Other comprehensive loss, net of income taxes | — | | | — | | | — | | | — | | | (17) | | | (1) | | | (18) | |
| | | | | | | | | | | | | |
| Balance, March 31, 2019 | 972,786 | | | $ | 19,171 | | | $ | (123) | | | $ | 15,321 | | | $ | (3,012) | | | $ | 2,347 | | | $ | 33,704 | |
| Net income | — | | | — | | | — | | | 484 | | | — | | | 10 | | | 494 | |
| Long-term incentive plan activity | 320 | | | 14 | | | 0 | | | 0 | | | 0 | | | 0 | | | 14 | |
| Employee stock purchase plan issuances | 311 | | | 24 | | | 0 | | | 0 | | | 0 | | | 0 | | | 24 | |
| | | | | | | | | | | | | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | 3 | | | 3 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Common stock dividends ($0.36/common share) | — | | | — | | | — | | | (353) | | | — | | | — | | | (353) | |
| Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 22 | | | (1) | | | 21 | |
| | | | | | | | | | | | | |
| Balance, June 30, 2019 | 973,417 | | | $ | 19,209 | | | $ | (123) | | | $ | 15,452 | | | $ | (2,990) | | | $ | 2,359 | | | $ | 33,907 | |
| Net Income (loss) | — | | | — | | | — | | | 772 | | | — | | | (12) | | | 760 | |
| Long-term incentive plan activity | 207 | | | 10 | | | — | | | — | | | — | | | — | | | 10 | |
| Employee stock purchase plan issuances | 317 | | | 19 | | | — | | | — | | | — | | | — | | | 19 | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | — | | | — | | | (18) | | | (18) | |
Common stock dividends ($0.36/common share) | — | | | — | | | — | | | (353) | | | — | | | — | | | (353) | |
| Other comprehensive income, net of income taxes | — | | | — | | | — | | | — | | | 27 | | | 0 | | | 27 | |
| Balance, September 30, 2019 | 973,941 | | | $ | 19,238 | | | $ | (123) | | | $ | 15,871 | | | $ | (2,963) | | | $ | 2,329 | | | $ | 34,352 | |
See the Combined Notes to Consolidated Financial Statements
15
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2018 |
(In millions, shares in thousands) | Issued Shares | | Common Stock | | Treasury Stock | | Retained Earnings | | Accumulated Other Comprehensive Loss, net | | Noncontrolling Interests | | Total Shareholders' Equity |
| Balance, December 31, 2017 | 965,168 |
| | $ | 18,964 |
| | $ | (123 | ) | | $ | 14,081 |
| | $ | (3,026 | ) | | $ | 2,291 |
| | $ | 32,187 |
|
| Net income | — |
| | — |
| | — |
| | 585 |
| | — |
| | 51 |
| | 636 |
|
| Long-term incentive plan activity | 1,685 |
| | (3 | ) | | — |
| | — |
| | — |
| | — |
| | (3 | ) |
| Employee stock purchase plan issuances | 361 |
| | 12 |
| | — |
| | — |
| | — |
| | — |
| | 12 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (9 | ) | | (9 | ) |
Common stock dividends ($0.35/common share) | — |
| | — |
| | — |
| | (334 | ) | | — |
| | — |
| | (334 | ) |
| Other comprehensive income, net of income taxes | — |
| | — |
| | — |
| | — |
| | 71 |
| | 1 |
| | 72 |
|
| Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard | — |
| | — |
| | — |
| | 14 |
| | (10 | ) | | — |
| | 4 |
|
| Balance, March 31, 2018 | 967,214 |
| | $ | 18,973 |
| | $ | (123 | ) | | $ | 14,346 |
| | $ | (2,965 | ) | | $ | 2,334 |
| | $ | 32,565 |
|
| Net income | — |
| | — |
| | — |
| | 539 |
| | — |
| | 3 |
| | 542 |
|
| Long-term incentive plan activity | 183 |
| | 20 |
| | — |
| | — |
| | — |
| | — |
| | 20 |
|
| Employee stock purchase plan issuances | 342 |
| | 15 |
| | — |
| | — |
| | — |
| | — |
| | 15 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (14 | ) | | (14 | ) |
Common stock dividends
($0.35/common share) | — |
| | — |
| | — |
| | (334 | ) | | — |
| | — |
| | (334 | ) |
| Other comprehensive income, net of income taxes | — |
| | — |
| | — |
| | — |
| | 44 |
| | 1 |
| | 45 |
|
| Balance, June 30, 2018 | 967,739 |
| | $ | 19,008 |
| | $ | (123 | ) | | $ | 14,551 |
| | $ | (2,921 | ) | | $ | 2,324 |
| | $ | 32,839 |
|
| Net Income | — |
| | — |
| | — |
| | 733 |
| | — |
| | 67 |
| | 800 |
|
| Long-term incentive plan activity | 809 |
| | 15 |
| | — |
| | — |
| | — |
| | — |
| | 15 |
|
| Employee stock purchase plan issuances | 294 |
| | 40 |
| | — |
| | — |
| | — |
| | — |
| | 40 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (23 | ) | | (23 | ) |
Common stock dividends
($0.35/common share) | — |
| | — |
| | — |
| | (335 | ) | | — |
| | — |
| | (335 | ) |
| Other comprehensive income, net of income taxes | — |
| | — |
| | — |
| | — |
| | 52 |
| | — |
| | 52 |
|
| Balance, September 30, 2018 | 968,842 |
| | $ | 19,063 |
| | $ | (123 | ) | | $ | 14,949 |
| | $ | (2,869 | ) | | $ | 2,368 |
| | $ | 33,388 |
|
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 | | 2020 | | 2019 |
| Operating revenues | | | | | | | |
| Operating revenues | $ | 4,328 | | | $ | 4,499 | | | $ | 12,340 | | | $ | 13,436 | |
| Operating revenues from affiliates | 331 | | | 275 | | | 932 | | | 844 | |
| Total operating revenues | 4,659 | | | 4,774 | | | 13,272 | | | 14,280 | |
| Operating expenses | | | | | | | |
| Purchased power and fuel | 2,311 | | | 2,648 | | | 6,967 | | | 8,141 | |
| Purchased power and fuel from affiliates | 3 | | | 3 | | | (6) | | | 7 | |
| Operating and maintenance | 1,605 | | | 947 | | | 3,779 | | | 3,131 | |
| Operating and maintenance from affiliates | 132 | | | 140 | | | 409 | | | 439 | |
| Depreciation and amortization | 558 | | | 407 | | | 1,161 | | | 1,221 | |
| Taxes other than income taxes | 118 | | | 129 | | | 364 | | | 394 | |
| Total operating expenses | 4,727 | | | 4,274 | | | 12,674 | | | 13,333 | |
| | | | | | | |
| (Loss) Gain on sales of assets and businesses | 0 | | | (18) | | | 12 | | | 15 | |
| | | | | | | |
| | | | | | | |
| Operating (loss) income | (68) | | | 482 | | | 610 | | | 962 | |
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (72) | | | (101) | | | (251) | | | (310) | |
| Interest expense to affiliates | (8) | | | (8) | | | (26) | | | (26) | |
| Other, net | 367 | | | 128 | | | 199 | | | 729 | |
| Total other income and (deductions) | 287 | | | 19 | | | (78) | | | 393 | |
| Income before income taxes | 219 | | | 501 | | | 532 | | | 1,355 | |
| Income taxes | 100 | | | 87 | | | 41 | | | 388 | |
| Equity in losses of unconsolidated affiliates | (2) | | | (170) | | | (6) | | | (183) | |
| Net income | 117 | | | 244 | | | 485 | | | 784 | |
| Net income (loss) attributable to noncontrolling interests | 68 | | | (13) | | | (85) | | | 56 | |
| Net income attributable to membership interest | $ | 49 | | | $ | 257 | | | $ | 570 | | | $ | 728 | |
| Comprehensive income, net of income taxes | | | | | | | |
| Net income | $ | 117 | | | $ | 244 | | | $ | 485 | | | $ | 784 | |
| Other comprehensive income (loss), net of income taxes | | | | | | | |
| Unrealized loss on cash flow hedges | 0 | | | 0 | | | (1) | | | 0 | |
| Unrealized gain on investments in unconsolidated affiliates | 0 | | | 5 | | | 0 | | | 1 | |
| Unrealized gain (loss) on foreign currency translation | 3 | | | (2) | | | (3) | | | 2 | |
| | | | | | | |
| | | | | | | |
| Other comprehensive income (loss) | 3 | | | 3 | | | (4) | | | 3 | |
| Comprehensive income | 120 | | | 247 | | | 481 | | | 787 | |
| Comprehensive income (loss) attributable to noncontrolling interests | 68 | | | (10) | | | (85) | | | 57 | |
| Comprehensive income attributable to membership interest | $ | 52 | | | $ | 257 | | | $ | 566 | | | $ | 730 | |
See the Combined Notes to Consolidated Financial Statements
16
|
| | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Operating revenues | | | | | | | |
| Operating revenues | $ | 4,499 |
| | $ | 4,970 |
| | $ | 13,436 |
| | $ | 14,389 |
|
| Operating revenues from affiliates | 275 |
| | 308 |
| | 844 |
| | 979 |
|
| Total operating revenues | 4,774 |
|
| 5,278 |
|
| 14,280 |
|
| 15,368 |
|
| Operating expenses | | | | | | | |
| Purchased power and fuel | 2,648 |
| | 2,977 |
| | 8,141 |
| | 8,542 |
|
| Purchased power and fuel from affiliates | 3 |
| | 3 |
| | 7 |
| | 10 |
|
| Operating and maintenance | 947 |
| | 1,218 |
| | 3,131 |
| | 3,643 |
|
| Operating and maintenance from affiliates | 140 |
| | 152 |
| | 439 |
| | 483 |
|
| Depreciation and amortization | 407 |
| | 468 |
| | 1,221 |
| | 1,383 |
|
| Taxes other than income | 129 |
| | 143 |
| | 394 |
| | 414 |
|
| Total operating expenses | 4,274 |
|
| 4,961 |
|
| 13,333 |
|
| 14,475 |
|
| (Loss) gain on sales of assets and businesses | (18 | ) | | (6 | ) | | 15 |
| | 48 |
|
| Operating income | 482 |
|
| 311 |
|
| 962 |
|
| 941 |
|
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (101 | ) | | (93 | ) | | (310 | ) | | (278 | ) |
| Interest expense to affiliates | (8 | ) | | (8 | ) | | (26 | ) | | (27 | ) |
| Other, net | 128 |
| | 179 |
| | 729 |
| | 164 |
|
| Total other income and (deductions) | 19 |
|
| 78 |
|
| 393 |
|
| (141 | ) |
| Income before income taxes | 501 |
| | 389 |
| | 1,355 |
| | 800 |
|
| Income taxes | 87 |
| | 78 |
| | 388 |
| | 110 |
|
| Equity in losses of unconsolidated affiliates | (170 | ) | | (11 | ) | | (183 | ) | | (23 | ) |
| Net income | 244 |
|
| 300 |
|
| 784 |
|
| 667 |
|
| Net (loss) income attributable to noncontrolling interests | (13 | ) | | 66 |
| | 56 |
| | 120 |
|
| Net income attributable to membership interest | $ | 257 |
|
| $ | 234 |
|
| $ | 728 |
|
| $ | 547 |
|
| Comprehensive income, net of income taxes | | | | | | | |
| Net income | $ | 244 |
| | $ | 300 |
| | $ | 784 |
| | $ | 667 |
|
| Other comprehensive income (loss), net of income taxes | | | | | | | |
| Unrealized gain on cash flow hedges | — |
| | — |
| | — |
| | 12 |
|
| Unrealized gain on investments in unconsolidated affiliates | 5 |
| | — |
| | 1 |
| | 3 |
|
| Unrealized (loss) gain on foreign currency translation | (2 | ) | | 2 |
| | 2 |
| | (4 | ) |
| Other comprehensive income | 3 |
|
| 2 |
|
| 3 |
|
| 11 |
|
| Comprehensive income | 247 |
|
| 302 |
|
| 787 |
|
| 678 |
|
| Comprehensive (loss) income attributable to noncontrolling interests | (10 | ) | | 66 |
| | 57 |
| | 122 |
|
| Comprehensive income attributable to membership interest | $ | 257 |
| | $ | 236 |
| | $ | 730 |
| | $ | 556 |
|
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | |
| Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 |
| Cash flows from operating activities | | | |
| Net income | $ | 485 | | | $ | 784 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | 2,266 | | | 2,377 | |
| Asset impairments | 552 | | | 174 | |
| | | |
| Gain on sales of assets and businesses | (12) | | | (15) | |
| | | |
| Deferred income taxes and amortization of investment tax credits | (51) | | | 201 | |
| Net fair value changes related to derivatives | (448) | | | 102 | |
| Net realized and unrealized gains on NDT funds | (59) | | | (467) | |
| Other non-cash operating activities | 293 | | | (95) | |
| Changes in assets and liabilities: | | | |
| Accounts receivable | 1,463 | | | 395 | |
| Receivables from and payables to affiliates, net | 75 | | | (12) | |
| Inventories | (65) | | | (36) | |
| Accounts payable and accrued expenses | (619) | | | (428) | |
| Option premiums (paid) received, net | (131) | | | 13 | |
| Collateral posted, net | 640 | | | (292) | |
| Income taxes | 112 | | | 327 | |
| Pension and non-pension postretirement benefit contributions | (249) | | | (165) | |
| Other assets and liabilities | (2,889) | | | (390) | |
| Net cash flows provided by operating activities | 1,363 | | | 2,473 | |
| Cash flows from investing activities | | | |
| Capital expenditures | (1,212) | | | (1,282) | |
| | | |
| Proceeds from NDT fund sales | 3,370 | | | 8,443 | |
| Investment in NDT funds | (3,438) | | | (8,437) | |
| | | |
| Collection of DPP | 2,518 | | | 0 | |
| Proceeds from sales of assets and businesses | 46 | | | 17 | |
| | | |
| | | |
| | | |
| Other investing activities | 5 | | | (6) | |
| Net cash flows provided by (used in) investing activities | 1,289 | | | (1,265) | |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | (280) | | | 0 | |
| Proceeds from short-term borrowings with maturities greater than 90 days | 500 | | | 0 | |
| | | |
| Issuance of long-term debt | 2,405 | | | 41 | |
| Retirement of long-term debt | (3,613) | | | (196) | |
| | | |
| Changes in Exelon intercompany money pool | 0 | | | (100) | |
| Distributions to member | (1,406) | | | (674) | |
| | | |
| Contributions from member | 64 | | | 0 | |
| | | |
| | | |
| Other financing activities | (48) | | | (37) | |
| Net cash flows used in financing activities | (2,378) | | | (966) | |
| Increase in cash, cash equivalents, and restricted cash | 274 | | | 242 | |
| Cash, cash equivalents, and restricted cash at beginning of period | 449 | | | 903 | |
| Cash, cash equivalents, and restricted cash at end of period | $ | 723 | | | $ | 1,145 | |
| | | |
| Supplemental cash flow information | | | |
| Decrease in capital expenditures not paid | $ | (77) | | | $ | (24) | |
| Increase in DPP | 3,275 | | | 0 | |
| Increase in PPE related to ARO update | 775 | | | 342 | |
| | | |
See the Combined Notes to Consolidated Financial Statements
17
|
| | | | | | | |
| | Nine Months Ended
September 30, |
| (In millions) | 2019 | | 2018 |
| Cash flows from operating activities | | | |
| Net income | $ | 784 |
| | $ | 667 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization | 2,377 |
| | 2,608 |
|
| Asset impairments | 174 |
| | 49 |
|
| Gain on sales of assets and businesses | (15 | ) | | (48 | ) |
| Deferred income taxes and amortization of investment tax credits | 201 |
| | (278 | ) |
| Net fair value changes related to derivatives | 102 |
| | 73 |
|
| Net realized and unrealized gains on NDT funds | (467 | ) | | (21 | ) |
| Other non-cash operating activities | (95 | ) | | 187 |
|
| Changes in assets and liabilities: |
| |
|
| Accounts receivable | 395 |
| | 126 |
|
| Receivables from and payables to affiliates, net | (12 | ) | | (7 | ) |
| Inventories | (36 | ) | | (10 | ) |
| Accounts payable and accrued expenses | (428 | ) | | (59 | ) |
| Option premiums received (paid), net | 13 |
| | (36 | ) |
| Collateral (posted) received, net | (292 | ) | | 228 |
|
| Income taxes | 327 |
| | 220 |
|
| Pension and non-pension postretirement benefit contributions | (165 | ) | | (134 | ) |
| Other assets and liabilities | (390 | ) | | (154 | ) |
| Net cash flows provided by operating activities | 2,473 |
|
| 3,411 |
|
| Cash flows from investing activities | | | |
| Capital expenditures | (1,282 | ) | | (1,660 | ) |
| Proceeds from NDT fund sales | 8,443 |
| | 6,379 |
|
| Investment in NDT funds | (8,437 | ) | | (6,553 | ) |
| Acquisition of assets and businesses, net | — |
| | (57 | ) |
| Proceeds from sales of assets and businesses | 17 |
| | 90 |
|
| Other investing activities | (6 | ) | | (5 | ) |
| Net cash flows used in investing activities | (1,265 | ) |
| (1,806 | ) |
| Cash flows from financing activities | | | |
| Issuance of long-term debt | 41 |
| | 14 |
|
| Retirement of long-term debt | (196 | ) | | (100 | ) |
| Changes in Exelon intercompany money pool | (100 | ) | | (54 | ) |
| Distributions to member | (674 | ) | | (688 | ) |
| Contributions from member | — |
|
| 54 |
|
| Other financing activities | (37 | ) | | (46 | ) |
| Net cash flows used in financing activities | (966 | ) |
| (820 | ) |
| Increase in cash, cash equivalents and restricted cash | 242 |
| | 785 |
|
| Cash, cash equivalents and restricted cash at beginning of period | 903 |
| | 554 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 1,145 |
|
| $ | 1,339 |
|
| | | | |
| Supplemental cash flow information | | | |
| Decrease in capital expenditures not paid | $ | (24 | ) | | $ | (226 | ) |
| Increase in PPE related to ARO update | 342 |
| | 47 |
|
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 623 | | | $ | 303 | |
| Restricted cash and cash equivalents | 100 | | | 146 | |
| Accounts receivable | | | |
| Customer accounts receivable | 1,089 | | 2,973 |
| Customer allowance for credit losses | (33) | | (80) |
| Customer accounts receivable, net | 1,056 | | | 2,893 | |
| Other accounts receivable | 311 | | 619 |
| | | |
| Other accounts receivable, net | 311 | | | 619 | |
| Mark-to-market derivative assets | 471 | | | 675 | |
| Receivables from affiliates | 109 | | | 190 | |
| | | |
| Unamortized energy contract assets | 41 | | | 47 | |
| Inventories, net | | | |
| Fossil fuel and emission allowances | 238 | | | 236 | |
| Materials and supplies | 971 | | | 1,026 | |
| | | |
| Renewable energy credits | 576 | | | 336 | |
| Other | 1,387 | | | 605 | |
| Total current assets | 5,883 | | | 7,076 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $12,588 and $12,017 as of September 30, 2020 and December 31, 2019, respectively) | 23,709 | | | 24,193 | |
| Deferred debits and other assets | | | |
| Nuclear decommissioning trust funds | 13,432 | | | 13,190 | |
| Investments | 197 | | | 235 | |
| Goodwill | 47 | | | 47 | |
| Mark-to-market derivative assets | 383 | | | 508 | |
| | | |
| Prepaid pension asset | 1,584 | | | 1,438 | |
| | | |
| Unamortized energy contract assets | 308 | | | 336 | |
| Deferred income taxes | 9 | | | 12 | |
| Other | 1,820 | | | 1,960 | |
| Total deferred debits and other assets | 17,780 | | | 17,726 | |
Total assets(a) | $ | 47,372 | | | $ | 48,995 | |
See the Combined Notes to Consolidated Financial Statements
18
|
| | | | | | | |
| (In millions) | September 30, 2019 | | December 31, 2018 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 1,019 |
| | $ | 750 |
|
| Restricted cash and cash equivalents | 126 |
| | 153 |
|
| Accounts receivable, net | | | |
| Customer (net of allowance for uncollectible accounts of $75 and $103 as of September 30, 2019 and December 31, 2018, respectively) | 2,587 |
| | 2,941 |
|
| Other (net of allowance for uncollectible accounts of $1 as of both September 30, 2019 and December 31, 2018) | 337 |
| | 562 |
|
| Mark-to-market derivative assets | 602 |
| | 804 |
|
| Receivables from affiliates | 166 |
| | 173 |
|
| Unamortized energy contract assets | 49 |
| | 49 |
|
| Inventories, net | | | |
| Fossil fuel and emission allowances | 243 |
| | 251 |
|
| Materials and supplies | 1,010 |
| | 963 |
|
| Assets held for sale | 18 |
| | 904 |
|
| Other | 1,002 |
| | 883 |
|
| Total current assets | 7,159 |
|
| 8,433 |
|
| Property, plant and equipment (net of accumulated depreciation and amortization of $11,972 and $12,206 as of September 30, 2019 and December 31, 2018, respectively) | 23,591 |
| | 23,981 |
|
| Deferred debits and other assets | | | |
| Nuclear decommissioning trust funds | 12,706 |
| | 11,661 |
|
| Investments | 248 |
| | 414 |
|
| Goodwill | 47 |
| | 47 |
|
| Mark-to-market derivative assets | 483 |
| | 452 |
|
| Prepaid pension asset | 1,472 |
| | 1,421 |
|
| Unamortized energy contract assets | 352 |
| | 371 |
|
| Deferred income taxes | 11 |
| | 21 |
|
| Other | 1,915 |
| | 755 |
|
| Total deferred debits and other assets | 17,234 |
|
| 15,142 |
|
Total assets(a) | $ | 47,984 |
|
| $ | 47,556 |
|
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | (In millions) | September 30, 2019 | | December 31, 2018 | (In millions) | September 30, 2020 | | December 31, 2019 |
| LIABILITIES AND EQUITY | | | | LIABILITIES AND EQUITY | | | |
| Current liabilities | | | | Current liabilities | |
| Short-term borrowings | | Short-term borrowings | $ | 540 | | | $ | 320 | |
| Long-term debt due within one year | $ | 2,706 |
| | $ | 906 |
| Long-term debt due within one year | 203 | | | 2,624 | |
| Long-term debt to affiliates due within one year | | Long-term debt to affiliates due within one year | 551 | | | 558 | |
| Accounts payable | 1,583 |
| | 1,847 |
| Accounts payable | 1,109 | | | 1,692 | |
| Accrued expenses | 762 |
| | 898 |
| Accrued expenses | 699 | | | 786 | |
| Payables to affiliates | 134 |
| | 139 |
| Payables to affiliates | 113 | | | 117 | |
| Borrowings from Exelon intercompany money pool | — |
| | 100 |
| |
| | Mark-to-market derivative liabilities | 212 |
| | 449 |
| Mark-to-market derivative liabilities | 147 | | | 215 | |
| Unamortized energy contract liabilities | 21 |
| | 31 |
| Unamortized energy contract liabilities | 8 | | | 17 | |
| Renewable energy credit obligation | 374 |
| | 343 |
| Renewable energy credit obligation | 604 | | | 443 | |
| Liabilities held for sale | 11 |
| | 777 |
| |
| | Other | 541 |
| | 279 |
| Other | 437 | | | 517 | |
| Total current liabilities | 6,344 |
| | 5,769 |
| Total current liabilities | 4,411 | | | 7,289 | |
| Long-term debt | 5,018 |
| | 6,989 |
| Long-term debt | 5,677 | | | 4,464 | |
| Long-term debt to affiliates | 889 |
| | 898 |
| Long-term debt to affiliates | 325 | | | 328 | |
| | Deferred credits and other liabilities | | | | Deferred credits and other liabilities | |
| Deferred income taxes and unamortized investment tax credits | 3,607 |
| | 3,383 |
| Deferred income taxes and unamortized investment tax credits | 3,715 | | | 3,752 | |
| Asset retirement obligations | 9,855 |
| | 9,450 |
| Asset retirement obligations | 11,744 | | | 10,603 | |
| | Non-pension postretirement benefit obligations | 885 |
| | 900 |
| Non-pension postretirement benefit obligations | 864 | | | 878 | |
| Spent nuclear fuel obligation | 1,193 |
| | 1,171 |
| Spent nuclear fuel obligation | 1,207 | | | 1,199 | |
| Payables to affiliates | 2,960 |
| | 2,606 |
| Payables to affiliates | 2,888 | | | 3,103 | |
| Mark-to-market derivative liabilities | 163 |
| | 252 |
| Mark-to-market derivative liabilities | 121 | | | 123 | |
| Unamortized energy contract liabilities | 11 |
| | 20 |
| Unamortized energy contract liabilities | 8 | | | 11 | |
| | Other | 1,466 |
| | 610 |
| Other | 1,488 | | | 1,415 | |
| Total deferred credits and other liabilities | 20,140 |
| | 18,392 |
| Total deferred credits and other liabilities | 22,035 | | | 21,084 | |
Total liabilities(a) | 32,391 |
| | 32,048 |
| Total liabilities(a) | 32,448 | | | 33,165 | |
| Commitments and contingencies |
| |
| Commitments and contingencies | | | |
| | Equity | | | | Equity | |
| Member’s equity | | | | Member’s equity | |
| Membership interest | 9,525 |
| | 9,518 |
| Membership interest | 9,633 | | | 9,566 | |
| Undistributed earnings | 3,778 |
| | 3,724 |
| Undistributed earnings | 3,114 | | | 3,950 | |
| Accumulated other comprehensive loss, net | (36 | ) | | (38 | ) | Accumulated other comprehensive loss, net | (36) | | | (32) | |
| Total member’s equity | 13,267 |
| | 13,204 |
| Total member’s equity | 12,711 | | | 13,484 | |
| Noncontrolling interests | 2,326 |
| | 2,304 |
| Noncontrolling interests | 2,213 | | | 2,346 | |
| Total equity | 15,593 |
| | 15,508 |
| Total equity | 14,924 | | | 15,830 | |
| Total liabilities and equity | $ | 47,984 |
| | $ | 47,556 |
| Total liabilities and equity | $ | 47,372 | | | $ | 48,995 | |
__________
| |
(a) | Generation’s consolidated assets include $9,443 million and $9,634 million at September 30, 2019 and December 31, 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,467 million and $3,480 million at September 30, 2019 and December 31, 2018, 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 $10,082 million and $9,512 million at September 30, 2020 and December 31, 2019, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,499 million and $3,429 million at September 30, 2020 and December 31, 2019, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 16 — Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
19
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| Member’s Equity | | | | |
| (In millions) | Membership
Interest | | Undistributed
Earnings | | Accumulated
Other
Comprehensive
Loss, net | | Noncontrolling
Interests | | Total Equity |
| Balance, December 31, 2019 | $ | 9,566 | | | $ | 3,950 | | | $ | (32) | | | $ | 2,346 | | | $ | 15,830 | |
| Net income (loss) | — | | | 45 | | | — | | | (206) | | | (161) | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | (11) | | | (11) | |
| Sale of noncontrolling interests | 2 | | | — | | | — | | | — | | | 2 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Distributions to member | — | | | (468) | | | — | | | — | | | (468) | |
| Other comprehensive loss, net of income taxes | — | | | 0 | | | (9) | | | 0 | | | (9) | |
| | | | | | | | | |
| Balance, March 31, 2020 | $ | 9,568 | | | $ | 3,527 | | | $ | (41) | | | $ | 2,129 | | | $ | 15,183 | |
| Net income | — | | | 476 | | | — | | | 53 | | | 529 | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | (19) | | | (19) | |
| Sale of noncontrolling interests | 1 | | | — | | | — | | | — | | | 1 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Distributions to member | — | | | (469) | | | — | | | — | | | (469) | |
| Other comprehensive loss, net of income taxes | — | | | 0 | | | 2 | | | 0 | | | 2 | |
| Balance, June 30, 2020 | $ | 9,569 | | | $ | 3,534 | | | $ | (39) | | | $ | 2,163 | | | $ | 15,227 | |
| Net income | — | | | 49 | | | — | | | 68 | | | 117 | |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | (18) | | | (18) | |
| Sale of noncontrolling interests | 0 | | | — | | | — | | | — | | | 0 | |
| | | | | | | | | |
| | | | | | | | | |
| Contribution from member | 64 | | | — | | | — | | | — | | | 64 | |
| Distributions to member | — | | | (469) | | | — | | | — | | | (469) | |
| Other comprehensive income, net of income taxes | — | | | 0 | | | 3 | | | 0 | | | 3 | |
| Balance, September 30, 2020 | $ | 9,633 | | | $ | 3,114 | | | $ | (36) | | | $ | 2,213 | | | $ | 14,924 | |
See the Combined Notes to Consolidated Financial Statements
20
| | | | Nine Months Ended September 30, 2019 | | Nine Months Ended September 30, 2019 |
| | Member’s Equity | | | | | | Member’s Equity | |
| (In millions) | Membership Interest | | Undistributed Earnings | | Accumulated Other Comprehensive Loss, net | | Noncontrolling Interests | | Total Equity | (In millions) | Membership
Interest | | Undistributed
Earnings | | Accumulated
Other
Comprehensive
Loss, net | | Noncontrolling
Interests | | Total Equity |
| Balance, December 31, 2018 | $ | 9,518 |
| | $ | 3,724 |
| | $ | (38 | ) | | $ | 2,304 |
| | $ | 15,508 |
| Balance, December 31, 2018 | $ | 9,518 | | | $ | 3,724 | | | $ | (38) | | | $ | 2,304 | | | $ | 15,508 | |
| Net income | — |
| | 363 |
| | — |
| | 59 |
| | 422 |
| Net income | — | | | 363 | | | — | | | 59 | | | 422 | |
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | (17 | ) | | (17 | ) | Changes in equity of noncontrolling interests | — | | | — | | | — | | | (17) | | | (17) | |
| Sale of noncontrolling interests | 7 |
| | — |
| | — |
| | — |
| | 7 |
| Sale of noncontrolling interests | 7 | | | — | | | — | | | — | | | 7 | |
| | Distributions to member | — |
| | (225 | ) | | — |
| | — |
| | (225 | ) | Distributions to member | — | | | (225) | | | — | | | — | | | (225) | |
| Other comprehensive income (loss), net of income taxes | — |
| | — |
| | 2 |
| | (1 | ) | | 1 |
| |
| Other comprehensive income, net of income taxes | | Other comprehensive income, net of income taxes | — | | | 0 | | | 2 | | | (1) | | | 1 | |
| | Balance, March 31, 2019 | $ | 9,525 |
|
| $ | 3,862 |
|
| $ | (36 | ) |
| $ | 2,345 |
|
| $ | 15,696 |
| Balance, March 31, 2019 | $ | 9,525 | | | $ | 3,862 | | | $ | (36) | | | $ | 2,345 | | | $ | 15,696 | |
| Net income | — |
| | 108 |
| | — |
| | 10 |
| | 118 |
| Net income | — | | | 108 | | | — | | | 10 | | | 118 | |
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | 3 |
| | 3 |
| Changes in equity of noncontrolling interests | — | | | — | | | — | | | 3 | | | 3 | |
| | Distributions to member | — |
| | (224 | ) | | — |
| | — |
| | (224 | ) | Distributions to member | — | | | (224) | | | — | | | — | | | (224) | |
| Other comprehensive loss, net of income taxes | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) | |
| Other comprehensive income, net of income taxes | | Other comprehensive income, net of income taxes | — | | | 0 | | | 0 | | | (1) | | | (1) | |
| Balance, June 30, 2019 | $ | 9,525 |
| | $ | 3,746 |
| | $ | (36 | ) | | $ | 2,357 |
| | $ | 15,592 |
| Balance, June 30, 2019 | $ | 9,525 | | | $ | 3,746 | | | $ | (36) | | | $ | 2,357 | | | $ | 15,592 | |
| Net income (loss) | — |
| | 257 |
| | — |
| | (13 | ) | | 244 |
| Net income (loss) | — | | | 257 | | | — | | | (13) | | | 244 | |
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | (18 | ) | | (18 | ) | Changes in equity of noncontrolling interests | — | | | — | | | — | | | (18) | | | (18) | |
| | Distributions to member | — |
| | (225 | ) | | — |
| | — |
| | (225 | ) | Distributions to member | — | | | (225) | | | — | | | — | | | (225) | |
| | Balance, September 30, 2019 | $ | 9,525 |
| | $ | 3,778 |
| | $ | (36 | ) | | $ | 2,326 |
| | $ | 15,593 |
| Balance, September 30, 2019 | $ | 9,525 | | | $ | 3,778 | | | $ | (36) | | | $ | 2,326 | | | $ | 15,593 | |
See the Combined Notes to Consolidated Financial Statements
21
|
| | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2018 |
| | Member’s Equity | | | | |
| (In millions) | Membership Interest | | Undistributed Earnings | | Accumulated Other Comprehensive Loss, net | | Noncontrolling Interests | | Total Equity |
| Balance, December 31, 2017 | $ | 9,357 |
| | $ | 4,349 |
| | $ | (37 | ) | | $ | 2,290 |
| | $ | 15,959 |
|
| Net income | — |
| | 136 |
| | — |
| | 50 |
| | 186 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | (9 | ) | | (9 | ) |
| Distributions to member | — |
| | (188 | ) | | — |
| | — |
| | (188 | ) |
| Other comprehensive income, net of income taxes | — |
| | — |
| | 6 |
| | 1 |
| | 7 |
|
| Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard | — |
| | 6 |
| | (3 | ) | | — |
| | 3 |
|
| Balance, March 31, 2018 | $ | 9,357 |
| | $ | 4,303 |
| | $ | (34 | ) | | $ | 2,332 |
| | $ | 15,958 |
|
| Net income | — |
| | 178 |
| | — |
| | 3 |
| | 181 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | (13 | ) | | (13 | ) |
| Distributions to member | — |
| | (189 | ) | | — |
| | — |
| | (189 | ) |
| Other comprehensive income, net of income taxes | — |
| | — |
| | 1 |
| | 1 |
| | 2 |
|
| Balance, June 30, 2018 | $ | 9,357 |
| | $ | 4,292 |
| | $ | (33 | ) | | $ | 2,323 |
| | $ | 15,939 |
|
| Net income | — |
| | 234 |
| | — |
| | 66 |
| | 300 |
|
| Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | (23 | ) | | (23 | ) |
| Contribution from member | 54 |
| | — |
| | — |
| | — |
| | 54 |
|
| Distributions to member | — |
| | (312 | ) | | — |
| | — |
| | (312 | ) |
| Other comprehensive income, net of income taxes | — |
| | — |
| | 2 |
| | — |
| | 2 |
|
| Balance, September 30, 2018 | $ | 9,411 |
| | $ | 4,214 |
| | $ | (31 | ) | | $ | 2,366 |
| | $ | 15,960 |
|
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 | | 2020 | | 2019 |
| Operating revenues | | | | | | | |
| Electric operating revenues | $ | 1,666 | | | $ | 1,635 | | | $ | 4,519 | | | $ | 4,427 | |
| Revenues from alternative revenue programs | (38) | | | (56) | | | (51) | | | (98) | |
| Operating revenues from affiliates | 15 | | | 4 | | | 31 | | | 13 | |
| Total operating revenues | 1,643 | | | 1,583 | | | 4,499 | | | 4,342 | |
| Operating expenses | | | | | | | |
| Purchased power | 535 | | | 494 | | | 1,305 | | | 1,199 | |
| Purchased power from affiliate | 71 | | | 83 | | | 252 | | | 270 | |
| Operating and maintenance | 252 | | | 267 | | | 964 | | | 771 | |
| Operating and maintenance from affiliate | 69 | | | 73 | | | 209 | | | 196 | |
| Depreciation and amortization | 294 | | | 259 | | | 841 | | | 767 | |
| Taxes other than income taxes | 81 | | | 80 | | | 227 | | | 228 | |
| Total operating expenses | 1,302 | | | 1,256 | | | 3,798 | | | 3,431 | |
| Gain on sales of assets | 0 | | | 1 | | | 0 | | | 4 | |
| Operating income | 341 | | | 328 | | | 701 | | | 915 | |
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (92) | | | (87) | | | (277) | | | (258) | |
| Interest expense to affiliates | (3) | | | (4) | | | (10) | | | (10) | |
| Other, net | 10 | | | 8 | | | 32 | | | 27 | |
| Total other income and (deductions) | (85) | | | (83) | | | (255) | | | (241) | |
| Income before income taxes | 256 | | | 245 | | | 446 | | | 674 | |
| Income taxes | 60 | | | 45 | | | 142 | | | 130 | |
| | | | | | | |
| Net income | $ | 196 | | | $ | 200 | | | $ | 304 | | | $ | 544 | |
| Comprehensive income | $ | 196 | | | $ | 200 | | | $ | 304 | | | $ | 544 | |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Operating revenues | | | | | | | |
| Electric operating revenues | $ | 1,635 |
| | $ | 1,609 |
| | $ | 4,427 |
| | $ | 4,512 |
|
| Revenues from alternative revenue programs | (56 | ) | | (15 | ) | | (98 | ) | | (27 | ) |
| Operating revenues from affiliates | 4 |
| | 4 |
| | 13 |
| | 23 |
|
| Total operating revenues | 1,583 |
|
| 1,598 |
|
| 4,342 |
|
| 4,508 |
|
| Operating expenses | | | | | | | |
| Purchased power | 494 |
| | 496 |
| | 1,199 |
| | 1,281 |
|
| Purchased power from affiliate | 83 |
| | 123 |
| | 270 |
| | 421 |
|
| Operating and maintenance | 267 |
| | 276 |
| | 771 |
| | 785 |
|
| Operating and maintenance from affiliate | 73 |
| | 61 |
| | 196 |
| | 189 |
|
| Depreciation and amortization | 259 |
| | 237 |
| | 767 |
| | 696 |
|
| Taxes other than income | 80 |
| | 82 |
| | 228 |
| | 238 |
|
| Total operating expenses | 1,256 |
|
| 1,275 |
|
| 3,431 |
|
| 3,610 |
|
| Gain on sales of assets | 1 |
| | — |
| | 4 |
| | 5 |
|
| Operating income | 328 |
|
| 323 |
|
| 915 |
|
| 903 |
|
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (87 | ) | | (82 | ) | | (258 | ) | | (251 | ) |
| Interest expense to affiliates | (4 | ) | | (3 | ) | | (10 | ) | | (10 | ) |
| Other, net | 8 |
| | 7 |
| | 27 |
| | 21 |
|
| Total other income and (deductions) | (83 | ) |
| (78 | ) |
| (241 | ) |
| (240 | ) |
| Income before income taxes | 245 |
| | 245 |
| | 674 |
| | 663 |
|
| Income taxes | 45 |
| | 52 |
| | 130 |
| | 140 |
|
| Net income | $ | 200 |
|
| $ | 193 |
|
| $ | 544 |
|
| $ | 523 |
|
| Comprehensive income | $ | 200 |
| | $ | 193 |
| | $ | 544 |
| | $ | 523 |
|
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | |
| Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 |
| Cash flows from operating activities | | | |
| Net income | $ | 304 | | | $ | 544 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation, amortization, and accretion | 841 | | | 767 | |
| Asset impairments | 15 | | | 0 | |
| Deferred income taxes and amortization of investment tax credits | 205 | | | 115 | |
| | | |
| Other non-cash operating activities | 354 | | | 180 | |
| Changes in assets and liabilities: | | | |
| Accounts receivable | (104) | | | (38) | |
| Receivables from and payables to affiliates, net | (13) | | | (27) | |
| Inventories | (2) | | | (16) | |
| Accounts payable and accrued expenses | 21 | | | (132) | |
| Collateral received (posted), net | 3 | | | 43 | |
| Income taxes | (22) | | | 25 | |
| Pension and non-pension postretirement benefit contributions | (145) | | | (71) | |
| Other assets and liabilities | (380) | | | (245) | |
| Net cash flows provided by operating activities | 1,077 | | | 1,145 | |
| Cash flows from investing activities | | | |
| Capital expenditures | (1,583) | | | (1,413) | |
| | | |
| | | |
| | | |
| | | |
| Other investing activities | 0 | | | 25 | |
| Net cash flows used in investing activities | (1,583) | | | (1,388) | |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | 11 | | | 387 | |
| Issuance of long-term debt | 1,000 | | | 400 | |
| Retirement of long-term debt | (500) | | | (300) | |
| | | |
| Dividends paid on common stock | (374) | | | (380) | |
| Contributions from parent | 488 | | | 187 | |
| | | |
| | | |
| Other financing activities | (14) | | | (10) | |
| Net cash flows provided by financing activities | 611 | | | 284 | |
| Increase in cash, cash equivalents, and restricted cash | 105 | | | 41 | |
| Cash, cash equivalents, and restricted cash at beginning of period | 403 | | | 330 | |
| Cash, cash equivalents, and restricted cash at end of period | $ | 508 | | | $ | 371 | |
| | | |
| Supplemental cash flow information | | | |
| Increase (decrease) in capital expenditures not paid | $ | 49 | | | $ | (52) | |
| | | |
| | | |
See the Combined Notes to Consolidated Financial Statements
23
|
| | | | | | | |
| | Nine Months Ended
September 30, |
| (In millions) | 2019 | | 2018 |
| Cash flows from operating activities | | | |
| Net income | $ | 544 |
| | $ | 523 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation and amortization | 767 |
| | 696 |
|
| Deferred income taxes and amortization of investment tax credits | 115 |
| | 214 |
|
| Other non-cash operating activities | 180 |
| | 187 |
|
| Changes in assets and liabilities: | | | |
| Accounts receivable | (38 | ) | | (190 | ) |
| Receivables from and payables to affiliates, net | (27 | ) | | 8 |
|
| Inventories | (16 | ) | | 4 |
|
| Accounts payable and accrued expenses | (132 | ) | | (38 | ) |
| Collateral posted, net | 43 |
| | (10 | ) |
| Income taxes | 25 |
| | (65 | ) |
| Pension and non-pension postretirement benefit contributions | (71 | ) | | (41 | ) |
| Other assets and liabilities | (245 | ) | | (170 | ) |
| Net cash flows provided by operating activities | 1,145 |
|
| 1,118 |
|
| Cash flows from investing activities | | | |
| Capital expenditures | (1,413 | ) | | (1,540 | ) |
| Other investing activities | 25 |
| | 22 |
|
| Net cash flows used in investing activities | (1,388 | ) |
| (1,518 | ) |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | 387 |
| | — |
|
| Issuance of long-term debt | 400 |
| | 1,350 |
|
| Retirement of long-term debt | (300 | ) | | (840 | ) |
| Contributions from parent | 187 |
| | 387 |
|
| Dividends paid on common stock | (380 | ) | | (345 | ) |
| Other financing activities | (10 | ) | | (16 | ) |
| Net cash flows provided by financing activities | 284 |
|
| 536 |
|
| Increase in cash, cash equivalents and restricted cash | 41 |
| | 136 |
|
| Cash, cash equivalents and restricted cash at beginning of period | 330 |
| | 144 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 371 |
|
| $ | 280 |
|
| | | | |
| Supplemental cash flow information | | | |
| Decrease in capital expenditures not paid | $ | (52 | ) | | $ | (28 | ) |
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 76 | | | $ | 90 | |
| Restricted cash and cash equivalents | 305 | | | 150 | |
| Accounts receivable | | | |
| Customer accounts receivable | 707 | | 604 |
| Customer allowance for credit losses | (105) | | (59) |
| Customer accounts receivable, net | 602 | | | 545 | |
| Other accounts receivable | 309 | | 306 |
| Other allowance for credit losses | (27) | | (20) |
| Other accounts receivable, net | 282 | | | 286 | |
| | | |
| Receivables from affiliates | 20 | | | 28 | |
| | | |
| | | |
| Inventories, net | 160 | | | 159 | |
| | | |
| Regulatory assets | 274 | | | 281 | |
| | | |
| Other | 59 | | | 44 | |
| Total current assets | 1,778 | | | 1,583 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $5,533 and $5,168 as of September 30, 2020 and December 31, 2019, respectively) | 24,081 | | | 23,107 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 1,742 | | | 1,480 | |
| Investments | 6 | | | 6 | |
| | | |
| Goodwill | 2,625 | | | 2,625 | |
| Receivables from affiliates | 2,445 | | | 2,622 | |
| Prepaid pension asset | 1,050 | | | 995 | |
| | | |
| | | |
| Other | 516 | | | 347 | |
| Total deferred debits and other assets | 8,384 | | | 8,075 | |
| Total assets | $ | 34,243 | | | $ | 32,765 | |
See the Combined Notes to Consolidated Financial Statements
24
|
| | | | | | | |
| (In millions) | September 30, 2019 | | December 31, 2018 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 76 |
| | $ | 135 |
|
| Restricted cash | 124 |
| | 29 |
|
| Accounts receivable, net | | | |
| Customer (net of allowance for uncollectible accounts of $65 and $61 as of September 30, 2019 and December 31, 2018, respectively) | 561 |
| | 539 |
|
| Other (net of allowance for uncollectible accounts of $21 and $20 as of September 30, 2019 and December 31, 2018, respectively) | 322 |
| | 320 |
|
| Receivables from affiliates | 27 |
| | 20 |
|
| Inventories, net | 162 |
| | 148 |
|
| Regulatory assets | 286 |
| | 293 |
|
| Other | 48 |
| | 86 |
|
| Total current assets | 1,606 |
|
| 1,570 |
|
| Property, plant and equipment (net of accumulated depreciation and amortization of $5,046 and $4,684 as of September 30, 2019 and December 31, 2018, respectively) | 22,795 |
| | 22,058 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 1,436 |
| | 1,307 |
|
| Investments | 6 |
| | 6 |
|
| Goodwill | 2,625 |
| | 2,625 |
|
| Receivables from affiliates | 2,487 |
| | 2,217 |
|
| Prepaid pension asset | 1,020 |
| | 1,035 |
|
| Other | 351 |
| | 395 |
|
| Total deferred debits and other assets | 7,925 |
|
| 7,585 |
|
| Total assets | $ | 32,326 |
|
| $ | 31,213 |
|
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 141 | | | $ | 130 | |
| Long-term debt due within one year | 350 | | | 500 | |
| Accounts payable | 671 | | | 527 | |
| Accrued expenses | 282 | | | 385 | |
| Payables to affiliates | 82 | | | 103 | |
| | | |
| Customer deposits | 100 | | | 118 | |
| Regulatory liabilities | 251 | | | 200 | |
| Mark-to-market derivative liabilities | 30 | | | 32 | |
| | | |
| Deferred Prosecution Agreement payments | 200 | | | 0 | |
| Other | 140 | | | 122 | |
| Total current liabilities | 2,247 | | | 2,117 | |
| Long-term debt | 8,631 | | | 7,991 | |
| Long-term debt to financing trust | 205 | | | 205 | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 4,299 | | | 4,021 | |
| Asset retirement obligations | 126 | | | 128 | |
| | | |
| Non-pension postretirement benefits obligations | 175 | | | 180 | |
| | | |
| Regulatory liabilities | 6,420 | | | 6,542 | |
| Mark-to-market derivative liabilities | 274 | | | 269 | |
| | | |
| | | |
| Other | 771 | | | 635 | |
| Total deferred credits and other liabilities | 12,065 | | | 11,775 | |
| Total liabilities | 23,148 | | | 22,088 | |
| Commitments and contingencies | | | |
| Shareholders’ equity | | | |
| Common stock | 1,588 | | | 1,588 | |
| | | |
| | | |
| Other paid-in capital | 8,060 | | | 7,572 | |
| Retained deficit unappropriated | (1,700) | | | (1,639) | |
| Retained earnings appropriated | 3,147 | | | 3,156 | |
| | | |
| Total shareholders’ equity | 11,095 | | | 10,677 | |
| Total liabilities and shareholders’ equity | $ | 34,243 | | | $ | 32,765 | |
See the Combined Notes to Consolidated Financial Statements
25
|
| | | | | | | |
| (In millions) | September 30, 2019 | | December 31, 2018 |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 387 |
| | $ | — |
|
| Long-term debt due within one year | 500 |
| | 300 |
|
| Accounts payable | 520 |
| | 607 |
|
| Accrued expenses | 275 |
| | 373 |
|
| Payables to affiliates | 87 |
| | 119 |
|
| Customer deposits | 116 |
| | 111 |
|
| Regulatory liabilities | 193 |
| | 293 |
|
| Mark-to-market derivative liability | 27 |
| | 26 |
|
| Other | 138 |
| | 96 |
|
| Total current liabilities | 2,243 |
| | 1,925 |
|
| Long-term debt | 7,696 |
| | 7,801 |
|
| Long-term debt to financing trust | 205 |
| | 205 |
|
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 4,016 |
| | 3,813 |
|
| Asset retirement obligations | 120 |
| | 118 |
|
| Non-pension postretirement benefits obligations | 185 |
| | 201 |
|
| Regulatory liabilities | 6,390 |
| | 6,050 |
|
| Mark-to-market derivative liability | 253 |
| | 223 |
|
| Other | 621 |
| | 630 |
|
| Total deferred credits and other liabilities | 11,585 |
| | 11,035 |
|
| Total liabilities | 21,729 |
| | 20,966 |
|
| Commitments and contingencies |
| |
|
| Shareholders’ equity | | | |
| Common stock | 1,588 |
| | 1,588 |
|
| Other paid-in capital | 7,509 |
| | 7,322 |
|
| Retained deficit unappropriated | (1,639 | ) | | (1,639 | ) |
| Retained earnings appropriated | 3,139 |
| | 2,976 |
|
| Total shareholders’ equity | 10,597 |
| | 10,247 |
|
| Total liabilities and shareholders’ equity | $ | 32,326 |
| | $ | 31,213 |
|
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| (In millions) | Common
Stock | | Other
Paid-In
Capital | | Retained Deficit
Unappropriated | | Retained
Earnings
Appropriated | | Total
Shareholders’
Equity |
| Balance, December 31, 2019 | $ | 1,588 | | | $ | 7,572 | | | $ | (1,639) | | | $ | 3,156 | | | $ | 10,677 | |
| Net income | — | | | — | | | 168 | | | — | | | 168 | |
| Appropriation of retained earnings for future dividends | — | | | — | | | (168) | | | 168 | | | 0 | |
| Common stock dividends | — | | | — | | | — | | | (125) | | | (125) | |
| Contributions from parent | — | | | 125 | | | — | | | — | | | 125 | |
| Balance, March 31, 2020 | $ | 1,588 | | | $ | 7,697 | | | $ | (1,639) | | | $ | 3,199 | | | $ | 10,845 | |
| Net loss | — | | | — | | | (61) | | | — | | | (61) | |
| | | | | | | | | |
| Common stock dividends | — | | | — | | | — | | | (124) | | | (124) | |
| Contributions from parent | — | | | 124 | | | — | | | — | | | 124 | |
| Balance, June 30, 2020 | $ | 1,588 | | | $ | 7,821 | | | $ | (1,700) | | | $ | 3,075 | | | $ | 10,784 | |
| Net income | — | | | — | | | 196 | | | — | | | 196 | |
| Appropriation of retained earnings for future dividends | — | | | — | | | (196) | | | 196 | | | 0 | |
| Common stock dividends | — | | | — | | | — | | | (124) | | | (124) | |
| Contributions from parent | — | | | 239 | | | — | | | — | | | 239 | |
| Balance, September 30, 2020 | $ | 1,588 | | | $ | 8,060 | | | $ | (1,700) | | | $ | 3,147 | | | $ | 11,095 | |
| | | | | | | | | |
| Nine Months Ended September 30, 2019 |
| (In millions) | Common
Stock | | Other
Paid-In
Capital | | Retained Deficit
Unappropriated | | Retained
Earnings
Appropriated | | Total
Shareholders’
Equity |
| Balance, December 31, 2018 | $ | 1,588 | | | $ | 7,322 | | | $ | (1,639) | | | $ | 2,976 | | | $ | 10,247 | |
| Net income | — | | | — | | | 157 | | | — | | | 157 | |
| Appropriation of retained earnings for future dividends | — | | | — | | | (157) | | | 157 | | | 0 | |
| Common stock dividends | — | | | — | | | — | | | (127) | | | (127) | |
| Contributions from parent | — | | | 63 | | | — | | | — | | | 63 | |
| Balance, March 31, 2019 | $ | 1,588 | | | $ | 7,385 | | | $ | (1,639) | | | $ | 3,006 | | | $ | 10,340 | |
| Net income | — | | | — | | | 186 | | | — | | | 186 | |
| Appropriation of retained earnings for future dividends | — | | | — | | | (186) | | | 186 | | | 0 | |
| Common stock dividends | — | | | — | | | — | | | (127) | | | (127) | |
| Contributions from parent | — | | | 61 | | | — | | | — | | | 61 | |
| Balance, June 30, 2019 | $ | 1,588 | | | $ | 7,446 | | | $ | (1,639) | | | $ | 3,065 | | | $ | 10,460 | |
| Net income | — | | | — | | | 200 | | | — | | | 200 | |
| Appropriation of retained earnings for future dividends | — | | | — | | | (200) | | | 200 | | | 0 | |
| Common stock dividends | — | | | — | | | — | | | (126) | | | (126) | |
| Contributions from parent | — | | | 63 | | | — | | | — | | | 63 | |
| Balance, September 30, 2019 | $ | 1,588 | | | $ | 7,509 | | | $ | (1,639) | | | $ | 3,139 | | | $ | 10,597 | |
See the Combined Notes to Consolidated Financial Statements
26
|
| | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 |
| (In millions) | Common Stock | | Other Paid-In Capital | | Retained Deficit Unappropriated | | Retained Earnings Appropriated | | Total Shareholders’ Equity |
| Balance, December 31, 2018 | $ | 1,588 |
| | $ | 7,322 |
| | $ | (1,639 | ) | | $ | 2,976 |
| | $ | 10,247 |
|
| Net income | — |
| | — |
| | 157 |
| | — |
| | 157 |
|
| Appropriation of retained earnings for future dividends | — |
| | — |
| | (157 | ) | | 157 |
| | — |
|
| Common stock dividends | — |
| | — |
| | — |
| | (127 | ) | | (127 | ) |
| Contributions from parent | — |
| | 63 |
| | — |
| | — |
| | 63 |
|
| Balance, March 31, 2019 | $ | 1,588 |
| | $ | 7,385 |
| | $ | (1,639 | ) | | $ | 3,006 |
| | $ | 10,340 |
|
| Net income | — |
| | — |
| | 186 |
| | — |
| | 186 |
|
| Appropriation of retained earnings for future dividends | — |
| | — |
| | (186 | ) | | 186 |
| | — |
|
| Common stock dividends | — |
| | — |
| | — |
| | (127 | ) | | (127 | ) |
| Contributions from parent | — |
| | 61 |
| | — |
| | — |
| | 61 |
|
| Balance, June 30, 2019 | $ | 1,588 |
| | $ | 7,446 |
| | $ | (1,639 | ) | | $ | 3,065 |
| | $ | 10,460 |
|
| Net income | — |
| | — |
| | 200 |
| | — |
| | 200 |
|
| Appropriation of retained earnings for future dividends | — |
| | — |
| | (200 | ) | | 200 |
| | — |
|
| Common stock dividends | — |
| | — |
| | — |
| | (126 | ) | | (126 | ) |
| Contributions from parent | — |
| | 63 |
| | — |
| | — |
| | 63 |
|
| Balance, September 30, 2019 | $ | 1,588 |
| | $ | 7,509 |
| | $ | (1,639 | ) | | $ | 3,139 |
| | $ | 10,597 |
|
| | | | | | | | | | |
| | Nine Months Ended September 30, 2018 |
| (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 | — |
| | — |
| | 165 |
| | — |
| | 165 |
|
| Appropriation of retained earnings for future dividends | — |
| | — |
| | (165 | ) | | 165 |
| | — |
|
| Common stock dividends | — |
| | — |
| | — |
| | (114 | ) | | (114 | ) |
| Contributions from parent | — |
| | 113 |
| | — |
| | — |
| | 113 |
|
| Balance, March 31, 2018 | $ | 1,588 |
| | $ | 6,935 |
| | $ | (1,639 | ) | | $ | 2,822 |
| | $ | 9,706 |
|
| Net income | — |
| | — |
| | 164 |
| | — |
| | 164 |
|
| Appropriation of retained earnings for future dividends | — |
| | — |
| | (164 | ) | | 164 |
| | — |
|
| Common stock dividends | — |
| | — |
| | — |
| | (115 | ) | | (115 | ) |
| Contributions from parent | — |
| | 112 |
| | — |
| | — |
| | 112 |
|
| Balance, June 30, 2018 | $ | 1,588 |
| | $ | 7,047 |
| | $ | (1,639 | ) | | $ | 2,871 |
| | $ | 9,867 |
|
| Net income | — |
| | — |
| | 193 |
| | — |
| | 193 |
|
| Appropriation of retained earnings for future dividends | — |
| | — |
| | (193 | ) | | 193 |
| | — |
|
| Common stock dividends | — |
| | — |
| | — |
| | (115 | ) | | (115 | ) |
| Contributions from parent | — |
| | 162 |
| | — |
| | — |
| | 162 |
|
| Balance, September 30, 2018 | $ | 1,588 |
| | $ | 7,209 |
| | $ | (1,639 | ) | | $ | 2,949 |
| | $ | 10,107 |
|
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 | | 2020 | | 2019 |
| Operating revenues | | | | | | | |
| Electric operating revenues | $ | 751 | | | $ | 726 | | | $ | 1,931 | | | $ | 1,914 | |
| Natural gas operating revenues | 54 | | | 62 | | | 358 | | | 431 | |
| Revenues from alternative revenue programs | 5 | | | (11) | | | 10 | | | (16) | |
| Operating revenues from affiliates | 3 | | | 1 | | | 7 | | | 4 | |
| Total operating revenues | 813 | | | 778 | | | 2,306 | | | 2,333 | |
| Operating expenses | | | | | | | |
| Purchased power | 190 | | | 185 | | | 495 | | | 461 | |
| Purchased fuel | 12 | | | 18 | | | 129 | | | 184 | |
| Purchased power from affiliate | 67 | | | 43 | | | 144 | | | 122 | |
| Operating and maintenance | 214 | | | 182 | | | 628 | | | 531 | |
| Operating and maintenance from affiliates | 37 | | | 37 | | | 114 | | | 112 | |
| Depreciation and amortization | 85 | | | 83 | | | 259 | | | 247 | |
| Taxes other than income taxes | 53 | | | 47 | | | 131 | | | 126 | |
| Total operating expenses | 658 | | | 595 | | | 1,900 | | | 1,783 | |
| | | | | | | |
| Operating income | 155 | | | 183 | | | 406 | | | 550 | |
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (36) | | | (30) | | | (100) | | | (91) | |
| Interest expense to affiliates | (3) | | | (3) | | | (8) | | | (9) | |
| Other, net | 6 | | | 4 | | | 12 | | | 11 | |
| Total other income and (deductions) | (33) | | | (29) | | | (96) | | | (89) | |
| Income before income taxes | 122 | | | 154 | | | 310 | | | 461 | |
| Income taxes | (16) | | | 14 | | | (7) | | | 51 | |
| | | | | | | |
| Net income | $ | 138 | | | $ | 140 | | | $ | 317 | | | $ | 410 | |
| Comprehensive income | $ | 138 | | | $ | 140 | | | $ | 317 | | | $ | 410 | |
See the Combined Notes to Consolidated Financial Statements
27
|
| | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Operating revenues | | | | | | | |
| Electric operating revenues | $ | 726 |
| | $ | 697 |
| | $ | 1,914 |
| | $ | 1,886 |
|
| Natural gas operating revenues | 62 |
| | 57 |
| | 431 |
| | 382 |
|
| Revenues from alternative revenue programs | (11 | ) | | 1 |
| | (16 | ) | | 2 |
|
| Operating revenues from affiliates | 1 |
| | 2 |
| | 4 |
| | 5 |
|
| Total operating revenues | 778 |
|
| 757 |
|
| 2,333 |
|
| 2,275 |
|
| Operating expenses | | | | | | | |
| Purchased power | 185 |
| | 215 |
| | 461 |
| | 576 |
|
| Purchased fuel | 18 |
| | 14 |
| | 184 |
| | 148 |
|
| Purchased power from affiliate | 43 |
| | 34 |
| | 122 |
| | 94 |
|
| Operating and maintenance | 182 |
| | 184 |
| | 531 |
| | 572 |
|
| Operating and maintenance from affiliates | 37 |
| | 35 |
| | 112 |
| | 114 |
|
| Depreciation and amortization | 83 |
| | 75 |
| | 247 |
| | 224 |
|
| Taxes other than income | 47 |
| | 46 |
| | 126 |
| | 125 |
|
| Total operating expenses | 595 |
|
| 603 |
|
| 1,783 |
|
| 1,853 |
|
| Gain on sales of assets | — |
| | — |
| | — |
| | 1 |
|
| Operating income | 183 |
|
| 154 |
|
| 550 |
|
| 423 |
|
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (30 | ) | | (28 | ) | | (91 | ) | | (85 | ) |
| Interest expense to affiliates | (3 | ) | | (4 | ) | | (9 | ) | | (11 | ) |
| Other, net | 4 |
| | 2 |
| | 11 |
| | 4 |
|
| Total other income and (deductions) | (29 | ) |
| (30 | ) |
| (89 | ) |
| (92 | ) |
| Income before income taxes | 154 |
| | 124 |
| | 461 |
|
| 331 |
|
| Income taxes | 14 |
| | (2 | ) | | 51 |
| | (5 | ) |
| Net income | $ | 140 |
|
| $ | 126 |
|
| $ | 410 |
|
| $ | 336 |
|
| Comprehensive income | $ | 140 |
| | $ | 126 |
| | $ | 410 |
| | $ | 336 |
|
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | |
| Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 |
| Cash flows from operating activities | | | |
| Net income | $ | 317 | | | $ | 410 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation and amortization | 259 | | | 247 | |
| | | |
| | | |
| Deferred income taxes and amortization of investment tax credits | (5) | | | 6 | |
| Other non-cash operating activities | 27 | | | 28 | |
| Changes in assets and liabilities: | | | |
| Accounts receivable | (2) | | | 46 | |
| Receivables from and payables to affiliates, net | (7) | | | (12) | |
| Inventories | (3) | | | (3) | |
| Accounts payable and accrued expenses | 32 | | | (32) | |
| | | |
| Income taxes | 48 | | | (15) | |
| Pension and non-pension postretirement benefit contributions | (18) | | | (26) | |
| Other assets and liabilities | (13) | | | (111) | |
| Net cash flows provided by operating activities | 635 | | | 538 | |
| Cash flows from investing activities | | | |
| Capital expenditures | (824) | | | (675) | |
| Changes in Exelon intercompany money pool | 68 | | | 0 | |
| | | |
| Other investing activities | 4 | | | 7 | |
| Net cash flows used in investing activities | (752) | | | (668) | |
| Cash flows from financing activities | | | |
| | | |
| | | |
| Issuance of long-term debt | 350 | | | 325 | |
| | | |
| | | |
| | | |
| Dividends paid on common stock | (255) | | | (268) | |
| Contributions from parent | 248 | | | 174 | |
| | | |
| | | |
| Other financing activities | (4) | | | (6) | |
| Net cash flows provided by financing activities | 339 | | | 225 | |
| Increase in cash, cash equivalents, and restricted cash | 222 | | | 95 | |
| Cash, cash equivalents, and restricted cash at beginning of period | 27 | | | 135 | |
| Cash, cash equivalents, and restricted cash at end of period | $ | 249 | | | $ | 230 | |
| | | |
| Supplemental cash flow information | | | |
| Increase in capital expenditures not paid | $ | 28 | | | $ | 42 | |
| | | |
See the Combined Notes to Consolidated Financial Statements
28
|
| | | | | | | |
| | Nine Months Ended
September 30, |
| (In millions) | 2019 | | 2018 |
| Cash flows from operating activities | | | |
| Net income | $ | 410 |
| | $ | 336 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation and amortization | 247 |
| | 224 |
|
| Gain on sales of assets | — |
| | (1 | ) |
| Deferred income taxes and amortization of investment tax credits | 6 |
| | 5 |
|
| Other non-cash operating activities | 28 |
| | 41 |
|
| Changes in assets and liabilities: | | | |
| Accounts receivable | 46 |
| | (85 | ) |
| Receivables from and payables to affiliates, net | (12 | ) | | 1 |
|
| Inventories | (3 | ) | | (13 | ) |
| Accounts payable and accrued expenses | (32 | ) | | (1 | ) |
| Income taxes | (15 | ) | | (16 | ) |
| Pension and non-pension postretirement benefit contributions | (26 | ) | | (25 | ) |
| Other assets and liabilities | (111 | ) | | 26 |
|
| Net cash flows provided by operating activities | 538 |
|
| 492 |
|
| Cash flows from investing activities | | | |
| Capital expenditures | (675 | ) | | (615 | ) |
| Other investing activities | 7 |
| | 6 |
|
| Net cash flows used in investing activities | (668 | ) |
| (609 | ) |
| Cash flows from financing activities | | | |
| Issuance of long-term debt | 325 |
| | 700 |
|
| Retirement of long-term debt | — |
| | (500 | ) |
| Contributions from parent | 174 |
| | 71 |
|
| Dividends paid on common stock | (268 | ) | | (300 | ) |
| Other financing activities | (6 | ) | | (22 | ) |
| Net cash flows provided by (used in) financing activities | 225 |
|
| (51 | ) |
| Increase (decrease) in cash, cash equivalents and restricted cash | 95 |
| | (168 | ) |
| Cash, cash equivalents and restricted cash at beginning of period | 135 |
| | 275 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 230 |
|
| $ | 107 |
|
| | | | |
| Supplemental cash flow information | | | |
| Increase in capital expenditures not paid | $ | 42 |
| | $ | 4 |
|
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 242 | | | $ | 21 | |
| Restricted cash and cash equivalents | 7 | | | 6 | |
| Accounts receivable | | | |
| Customer accounts receivable | 412 | | 412 |
| Customer allowance for credit losses | (96) | | (55) |
| Customer accounts receivable, net | 316 | | | 357 | |
| Other accounts receivable | 126 | | 145 |
| Other allowance for credit losses | (7) | | (7) |
| Other accounts receivable, net | 119 | | | 138 | |
| | | |
| Receivables from affiliates | 0 | | | 1 | |
| Receivable from Exelon intercompany money pool | 0 | | | 68 | |
| | | |
| Inventories, net | | | |
| Fossil fuel | 36 | | | 36 | |
| Materials and supplies | 37 | | | 35 | |
| Prepaid utility taxes | 35 | | | 0 | |
| Regulatory assets | 38 | | | 41 | |
| | | |
| Other | 23 | | | 19 | |
| Total current assets | 853 | | | 722 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $3,804 and $3,718 as of September 30, 2020 and December 31, 2019, respectively) | 9,912 | | | 9,292 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 692 | | | 554 | |
| | | |
| Investments | 29 | | | 27 | |
| | | |
| | | |
| | | |
| Receivables from affiliates | 443 | | | 480 | |
| Prepaid pension asset | 377 | | | 365 | |
| | | |
| | | |
| Other | 28 | | | 29 | |
| Total deferred debits and other assets | 1,569 | | | 1,455 | |
| Total assets | $ | 12,334 | | | $ | 11,469 | |
See the Combined Notes to Consolidated Financial Statements
29
|
| | | | | | | |
| (In millions) | September 30, 2019 | | December 31, 2018 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 224 |
| | $ | 130 |
|
| Restricted cash and cash equivalents | 6 |
| | 5 |
|
| Accounts receivable, net | | | |
| Customer (net of allowance for uncollectible accounts of $54 and $53 as of September 30, 2019 and December 31, 2018, respectively) | 286 |
| | 321 |
|
| Other (net of allowance for uncollectible accounts of $7 and $8 as of September 30, 2019 and December 31, 2018, respectively) | 118 |
| | 151 |
|
| Receivable from affiliates | 7 |
| | — |
|
| Inventories, net | | | |
| Fossil fuel | 41 |
| | 38 |
|
| Materials and supplies | 37 |
| | 37 |
|
| Prepaid utility taxes | 34 |
| | — |
|
| Regulatory assets | 63 |
| | 81 |
|
| Other | 27 |
| | 19 |
|
| Total current assets | 843 |
|
| 782 |
|
| Property, plant and equipment (net of accumulated depreciation and amortization of $3,670 and $3,561 as of September 30, 2019 and December 31, 2018, respectively) | 9,100 |
| | 8,610 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 540 |
| | 460 |
|
| Investments | 26 |
| | 25 |
|
| Receivable from affiliates | 473 |
| | 389 |
|
| Prepaid pension asset | 367 |
| | 349 |
|
| Other | 30 |
| | 27 |
|
| Total deferred debits and other assets | 1,436 |
|
| 1,250 |
|
| Total assets | $ | 11,379 |
|
| $ | 10,642 |
|
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| | | |
| Long-term debt due within one year | $ | 300 | | | $ | 0 | |
| Accounts payable | 443 | | | 387 | |
| Accrued expenses | 124 | | | 101 | |
| Payables to affiliates | 47 | | | 55 | |
| | | |
| Customer deposits | 63 | | | 69 | |
| Regulatory liabilities | 129 | | | 91 | |
| | | |
| | | |
| Other | 27 | | | 19 | |
| Total current liabilities | 1,133 | | | 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 | 2,194 | | | 2,080 | |
| Asset retirement obligations | 29 | | | 28 | |
| Non-pension postretirement benefits obligations | 286 | | | 288 | |
| | | |
| Regulatory liabilities | 471 | | | 510 | |
| | | |
| | | |
| | | |
| | | |
| Other | 96 | | | 74 | |
| Total deferred credits and other liabilities | 3,076 | | | 2,980 | |
| Total liabilities | 7,846 | | | 7,291 | |
| Commitments and contingencies | | | |
| Shareholder’s equity | | | |
| Common stock | 3,014 | | | 2,766 | |
| | | |
| | | |
| Retained earnings | 1,474 | | | 1,412 | |
| | | |
| | | |
| Total shareholder’s equity | 4,488 | | | 4,178 | |
| Total liabilities and shareholder's equity | $ | 12,334 | | | $ | 11,469 | |
See the Combined Notes to Consolidated Financial Statements
30
|
| | | | | | | |
| (In millions) | September 30, 2019 | | December 31, 2018 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Accounts payable | 382 |
| | 370 |
|
| Accrued expenses | 97 |
| | 113 |
|
| Payables to affiliates | 54 |
| | 59 |
|
| Customer deposits | 69 |
| | 68 |
|
| Regulatory liabilities | 93 |
| | 175 |
|
| Other | 27 |
| | 24 |
|
| Total current liabilities | 722 |
| | 809 |
|
| Long-term debt | 3,404 |
| | 3,084 |
|
| Long-term debt to financing trusts | 184 |
| | 184 |
|
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 2,034 |
| | 1,933 |
|
| Asset retirement obligations | 28 |
| | 27 |
|
| Non-pension postretirement benefits obligations | 289 |
| | 288 |
|
| Regulatory liabilities | 503 |
| | 421 |
|
| Other | 79 |
| | 76 |
|
| Total deferred credits and other liabilities | 2,933 |
| | 2,745 |
|
| Total liabilities | 7,243 |
| | 6,822 |
|
| Commitments and contingencies |
| |
|
| Shareholder’s equity | | | |
| Common stock | 2,752 |
| | 2,578 |
|
| Retained earnings | 1,384 |
| | 1,242 |
|
| Total shareholder’s equity | 4,136 |
| | 3,820 |
|
| Total liabilities and shareholder's equity | $ | 11,379 |
| | $ | 10,642 |
|
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
| | | | | | | | | | | | | | | | | | | |
| Nine months ended September 30, 2020 |
| (In millions) | Common
Stock | | Retained
Earnings | | | | Total
Shareholder's
Equity |
| Balance, December 31, 2019 | $ | 2,766 | | | $ | 1,412 | | | | | $ | 4,178 | |
| Net income | — | | | 140 | | | | | 140 | |
| Common stock dividends | — | | | (85) | | | | | (85) | |
| Contributions from parent | 231 | | | — | | | | | 231 | |
| Balance, March 31, 2020 | $ | 2,997 | | | $ | 1,467 | | | | | $ | 4,464 | |
| Net income | — | | | 39 | | | | | 39 | |
| Common stock dividends | — | | | (85) | | | | | (85) | |
| | | | | | | |
| | | | | | | |
| Balance, June 30, 2020 | $ | 2,997 | | | $ | 1,421 | | | | | $ | 4,418 | |
| Net income | — | | | 138 | | | | | 138 | |
| Common stock dividends | — | | | (85) | | | | | (85) | |
| Contributions from parent | 17 | | | — | | | | | 17 | |
| Balance, September 30, 2020 | $ | 3,014 | | | $ | 1,474 | | | | | $ | 4,488 | |
| | | | | | | |
| Nine months ended September 30, 2019 |
| (In millions) | Common
Stock | | Retained
Earnings | | | | Total
Shareholder's
Equity |
| Balance, December 31, 2018 | $ | 2,578 | | | $ | 1,242 | | | | | $ | 3,820 | |
| Net income | — | | | 168 | | | | | 168 | |
| Common stock dividends | — | | | (90) | | | | | (90) | |
| Contributions from parent | 145 | | | — | | | | | 145 | |
| Balance, March 31, 2019 | $ | 2,723 | | | $ | 1,320 | | | | | $ | 4,043 | |
| Net income | — | | | 102 | | | | | 102 | |
| Common stock dividends | — | | | (90) | | | | | (90) | |
| | | | | | | |
| | | | | | | |
| Balance, June 30, 2019 | $ | 2,723 | | | $ | 1,332 | | | | | $ | 4,055 | |
| Net income | — | | | 140 | | | | | 140 | |
| Common stock dividends | — | | | (88) | | | | | (88) | |
| Contributions from parent | 29 | | | — | | | | | 29 | |
| Balance, September 30, 2019 | $ | 2,752 | | | $ | 1,384 | | | | | $ | 4,136 | |
|
| | | | | | | | | | | | | | | |
| | Nine months ended September 30, 2019 |
| (In millions) | Common Stock | | Retained Earnings | | Accumulated Other Comprehensive Income, net | | Total Shareholder's Equity |
| Balance, December 31, 2018 | $ | 2,578 |
| | $ | 1,242 |
| | $ | — |
| | $ | 3,820 |
|
| Net income | — |
| | 168 |
| | — |
| | 168 |
|
| Common stock dividends | — |
| | (90 | ) | | — |
| | (90 | ) |
| Contributions from parent | 145 |
| | — |
| | — |
| | 145 |
|
| Balance, March 31, 2019 | $ | 2,723 |
| | $ | 1,320 |
| | $ | — |
| | $ | 4,043 |
|
| Net income | — |
| | 102 |
| | — |
| | 102 |
|
| Common stock dividends | — |
| | (90 | ) | | — |
| | (90 | ) |
| Balance, June 30, 2019 | $ | 2,723 |
| | $ | 1,332 |
| | $ | — |
| | $ | 4,055 |
|
| Net income | — |
| | 140 |
| | — |
| | 140 |
|
| Common stock dividends | — |
| | (88 | ) | | — |
| | (88 | ) |
| Contributions from parent | 29 |
| | — |
| | — |
| | 29 |
|
| Balance, September 30, 2019 | $ | 2,752 |
| | $ | 1,384 |
| | $ | — |
| | $ | 4,136 |
|
| | | | | | | | |
| | Nine months ended September 30, 2018 |
| (In millions) | Common
Stock | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income, net | | Total
Shareholder's
Equity |
| Balance, December 31, 2017 | $ | 2,489 |
| | $ | 1,087 |
| | $ | 1 |
| | $ | 3,577 |
|
| Net income | — |
| | 113 |
| | — |
| | 113 |
|
| Common stock dividends | — |
| | (287 | ) | | — |
| | (287 | ) |
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities Standard | — |
| | 1 |
| | (1 | ) | | — |
|
| Balance, March 31, 2018 | $ | 2,489 |
| | $ | 914 |
| | $ | — |
| | $ | 3,403 |
|
| Net income | — |
| | 96 |
| | — |
| | 96 |
|
| Common stock dividends | — |
| | (5 | ) | | — |
| | (5 | ) |
| Contributions from parent | 41 |
| | — |
| | — |
| | 41 |
|
| Balance, June 30, 2018 | $ | 2,530 |
| | $ | 1,005 |
| | $ | — |
| | $ | 3,535 |
|
| Net income | — |
| | 126 |
| | — |
| | 126 |
|
| Common stock dividends | — |
| | (7 | ) | | — |
| | (7 | ) |
| Contributions from parent | 30 |
| | — |
| | — |
| | 30 |
|
| Balance, September 30, 2018 | $ | 2,560 |
| | $ | 1,124 |
| | $ | — |
| | $ | 3,684 |
|
See the Combined Notes to Consolidated Financial Statements
31
BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 | | 2020 | | 2019 |
| Operating revenues | | | | | | | |
| Electric operating revenues | $ | 649 | | | $ | 623 | | | $ | 1,775 | | | $ | 1,814 | |
| Natural gas operating revenues | 85 | | | 79 | | | 503 | | | 484 | |
| Revenues from alternative revenue programs | (9) | | | (5) | | | (10) | | | 11 | |
| Operating revenues from affiliates | 6 | | | 6 | | | 16 | | | 18 | |
| Total operating revenues | 731 | | | 703 | | | 2,284 | | | 2,327 | |
| Operating expenses | | | | | | | |
| Purchased power | 155 | | | 159 | | | 376 | | | 480 | |
| Purchased fuel | 12 | | | 12 | | | 106 | | | 128 | |
| Purchased power and fuel from affiliate | 83 | | | 64 | | | 249 | | | 196 | |
| Operating and maintenance | 152 | | | 157 | | | 445 | | | 451 | |
| Operating and maintenance from affiliates | 39 | | | 39 | | | 122 | | | 118 | |
| Depreciation and amortization | 133 | | | 116 | | | 405 | | | 368 | |
| Taxes other than income taxes | 68 | | | 65 | | | 200 | | | 195 | |
| Total operating expenses | 642 | | | 612 | | | 1,903 | | | 1,936 | |
| | | | | | | |
| Operating income | 89 | | | 91 | | | 381 | | | 391 | |
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (34) | | | (31) | | | (99) | | | (89) | |
| | | | | | | |
| Other, net | 6 | | | 7 | | | 17 | | | 18 | |
| Total other income and (deductions) | (28) | | | (24) | | | (82) | | | (71) | |
| Income before income taxes | 61 | | | 67 | | | 299 | | | 320 | |
| Income taxes | 8 | | | 12 | | | 26 | | | 59 | |
| | | | | | | |
| Net income | $ | 53 | | | $ | 55 | | | $ | 273 | | | $ | 261 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Comprehensive income | $ | 53 | | | $ | 55 | | | $ | 273 | | | $ | 261 | |
| | | | | | | |
| | | | | | | |
See the Combined Notes to Consolidated Financial Statements
32
|
| | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Operating revenues | | | | | | | |
| Electric operating revenues | $ | 623 |
| | $ | 652 |
| | $ | 1,814 |
| | $ | 1,847 |
|
| Natural gas operating revenues | 79 |
| | 79 |
| | 484 |
| | 527 |
|
| Revenues from alternative revenue programs | (5 | ) | | (6 | ) | | 11 |
| | (23 | ) |
| Operating revenues from affiliates | 6 |
| | 6 |
| | 18 |
| | 18 |
|
| Total operating revenues | 703 |
|
| 731 |
|
| 2,327 |
|
| 2,369 |
|
| Operating expenses | | | | | | | |
| Purchased power | 159 |
| | 183 |
| | 480 |
| | 510 |
|
| Purchased fuel | 12 |
| | 21 |
| | 128 |
| | 176 |
|
| Purchased power from affiliate | 64 |
| | 68 |
| | 196 |
| | 195 |
|
| Operating and maintenance | 157 |
| | 144 |
| | 451 |
| | 462 |
|
| Operating and maintenance from affiliates | 39 |
| | 38 |
| | 118 |
| | 116 |
|
| Depreciation and amortization | 116 |
| | 110 |
| | 368 |
| | 358 |
|
| Taxes other than income | 65 |
| | 64 |
| | 195 |
| | 188 |
|
| Total operating expenses | 612 |
|
| 628 |
|
| 1,936 |
|
| 2,005 |
|
| Gain on sales of assets | — |
| | — |
| | — |
| | 1 |
|
| Operating income | 91 |
|
| 103 |
|
| 391 |
|
| 365 |
|
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (31 | ) | | (27 | ) | | (89 | ) | | (78 | ) |
| Other, net | 7 |
| | 5 |
| | 18 |
| | 14 |
|
| Total other income and (deductions) | (24 | ) |
| (22 | ) |
| (71 | ) |
| (64 | ) |
| Income before income taxes | 67 |
| | 81 |
| | 320 |
|
| 301 |
|
| Income taxes | 12 |
| | 18 |
| | 59 |
| | 59 |
|
| Net income | $ | 55 |
|
| $ | 63 |
|
| $ | 261 |
|
| $ | 242 |
|
| Comprehensive income | $ | 55 |
| | $ | 63 |
| | $ | 261 |
| | $ | 242 |
|
BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | |
| Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 |
| Cash flows from operating activities | | | |
| Net income | $ | 273 | | | $ | 261 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation and amortization | 405 | | | 368 | |
| | | |
| Deferred income taxes and amortization of investment tax credits | 35 | | | 66 | |
| | | |
| Other non-cash operating activities | 82 | | | 63 | |
| Changes in assets and liabilities: | | | |
| Accounts receivable | (19) | | | 110 | |
| Receivables from and payables to affiliates, net | (27) | | | (14) | |
| Inventories | 2 | | | (5) | |
| Accounts payable and accrued expenses | 53 | | | (28) | |
| Collateral posted, net | 0 | | | (5) | |
| Income taxes | 46 | | | (43) | |
| Pension and non-pension postretirement benefit contributions | (74) | | | (45) | |
| Other assets and liabilities | (50) | | | (65) | |
| Net cash flows provided by operating activities | 726 | | | 663 | |
| Cash flows from investing activities | | | |
| Capital expenditures | (838) | | | (842) | |
| | | |
| Other investing activities | 0 | | | 4 | |
| Net cash flows used in investing activities | (838) | | | (838) | |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | (76) | | | (35) | |
| Issuance of long-term debt | 400 | | | 400 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Dividends paid on common stock | (186) | | | (169) | |
| Contributions from parent | 284 | | | 104 | |
| Other financing activities | (8) | | | (7) | |
| Net cash flows provided by financing activities | 414 | | | 293 | |
| Increase in cash, cash equivalents, and restricted cash | 302 | | | 118 | |
| Cash, cash equivalents, and restricted cash at beginning of period | 25 | | | 13 | |
| Cash, cash equivalents, and restricted cash at end of period | $ | 327 | | | $ | 131 | |
| | | |
| Supplemental cash flow information | | | |
| Increase in capital expenditures not paid | $ | 7 | | | $ | 6 | |
| | | |
| | | |
See the Combined Notes to Consolidated Financial Statements
33
|
| | | | | | | |
| | Nine Months Ended
September 30, |
| (In millions) | 2019 | | 2018 |
| Cash flows from operating activities | | | |
| Net income | $ | 261 |
| | $ | 242 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation and amortization | 368 |
| | 358 |
|
| Deferred income taxes and amortization of investment tax credits | 66 |
| | 82 |
|
| Other non-cash operating activities | 63 |
| | 42 |
|
| Changes in assets and liabilities: | | | |
| Accounts receivable | 110 |
| | 72 |
|
| Receivables from and payables to affiliates, net | (14 | ) | | (4 | ) |
| Inventories | (5 | ) | | (8 | ) |
| Accounts payable and accrued expenses | (28 | ) | | (3 | ) |
| Collateral (posted) received, net | (5 | ) | | 1 |
|
| Income taxes | (43 | ) | | (48 | ) |
| Pension and non-pension postretirement benefit contributions | (45 | ) | | (50 | ) |
| Other assets and liabilities | (65 | ) | | (9 | ) |
| Net cash flows provided by operating activities | 663 |
|
| 675 |
|
| Cash flows from investing activities | | | |
| Capital expenditures | (842 | ) | | (667 | ) |
| Other investing activities | 4 |
| | 8 |
|
| Net cash flows used in investing activities | (838 | ) |
| (659 | ) |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | (35 | ) | | (77 | ) |
| Issuance of long-term debt | 400 |
| | 300 |
|
| Dividends paid on common stock | (169 | ) | | (157 | ) |
| Contributions from parent | 104 |
| | 18 |
|
| Other financing activities | (7 | ) | | (2 | ) |
| Net cash flows provided by financing activities | 293 |
|
| 82 |
|
| Increase in cash, cash equivalents and restricted cash | 118 |
| | 98 |
|
| Cash, cash equivalents and restricted cash at beginning of period | 13 |
| | 18 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 131 |
|
| $ | 116 |
|
| | | | |
| Supplemental cash flow information | | | |
| Increase in capital expenditures not paid | $ | 6 |
| | $ | 44 |
|
BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 326 | | | $ | 24 | |
| Restricted cash and cash equivalents | 1 | | | 1 | |
| Accounts receivable | | | |
| Customer accounts receivable | 357 | | 329 |
| Customer allowance for credit losses | (35) | | (12) |
| Customer accounts receivable, net | 322 | | | 317 | |
| Other accounts receivable | 114 | | 152 |
| Other allowance for credit losses | (9) | | (5) |
| Other accounts receivable, net | 105 | | | 147 | |
| | | |
| Receivables from affiliates | 0 | | | 1 | |
| | | |
| | | |
| | | |
| Inventories, net | | | |
| Fossil fuel | 31 | | | 30 | |
| Materials and supplies | 43 | | | 46 | |
| Prepaid utility taxes | 0 | | | 78 | |
| Regulatory assets | 167 | | | 183 | |
| | | |
| Other | 6 | | | 6 | |
| Total current assets | 1,001 | | | 833 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $3,963 and $3,834 as of September 30, 2020 and December 31, 2019, respectively) | 9,541 | | | 8,990 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 473 | | | 454 | |
| | | |
| Investments | 8 | | | 7 | |
| | | |
| | | |
| | | |
| Prepaid pension asset | 283 | | | 264 | |
| | | |
| | | |
| Other | 64 | | | 86 | |
| Total deferred debits and other assets | 828 | | | 811 | |
| Total assets | $ | 11,370 | | | $ | 10,634 | |
See the Combined Notes to Consolidated Financial Statements
34
|
| | | | | | | |
| (In millions) | September 30, 2019 | | December 31, 2018 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 130 |
| | $ | 7 |
|
| Restricted cash and cash equivalents | 1 |
| | 6 |
|
| Accounts receivable, net | | | |
| Customer (net of allowance for uncollectible accounts of $13 and $16 as of September 30, 2019 and December 31, 2018, respectively) | 242 |
| | 353 |
|
| Other (net of allowance for uncollectible accounts of $4 as of both September 30, 2019 and December 31, 2018) | 110 |
| | 90 |
|
| Receivables from affiliates | 1 |
| | 1 |
|
| Inventories, net | | | |
| Fossil fuel | 34 |
| | 36 |
|
| Materials and supplies | 46 |
| | 39 |
|
| Prepaid utility taxes | — |
| | 74 |
|
| Regulatory assets | 180 |
| | 177 |
|
| Other | 7 |
| | 3 |
|
| Total current assets | 751 |
|
| 786 |
|
| Property, plant and equipment (net of accumulated depreciation and amortization of $3,772 and $3,633 as of September 30, 2019 and December 31, 2018, respectively) | 8,796 |
| | 8,243 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 386 |
| | 398 |
|
| Investments | 7 |
| | 5 |
|
| Prepaid pension asset | 276 |
| | 279 |
|
| Other | 88 |
| | 5 |
|
| Total deferred debits and other assets | 757 |
|
| 687 |
|
| Total assets | $ | 10,304 |
|
| $ | 9,716 |
|
BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 0 | | | $ | 76 | |
| | | |
| Accounts payable | 273 | | | 243 | |
| Accrued expenses | 178 | | | 152 | |
| Payables to affiliates | 39 | | | 66 | |
| | | |
| Customer deposits | 115 | | | 120 | |
| Regulatory liabilities | 39 | | | 33 | |
| | | |
| | | |
| Other | 76 | | | 63 | |
| Total current liabilities | 720 | | | 753 | |
| Long-term debt | 3,664 | | | 3,270 | |
| | | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 1,504 | | | 1,396 | |
| Asset retirement obligations | 24 | | | 22 | |
| Non-pension postretirement benefits obligations | 190 | | | 199 | |
| | | |
| Regulatory liabilities | 1,121 | | | 1,195 | |
| | | |
| | | |
| | | |
| | | |
| Other | 93 | | | 116 | |
| Total deferred credits and other liabilities | 2,932 | | | 2,928 | |
| Total liabilities | 7,316 | | | 6,951 | |
| Commitments and contingencies | | | |
| Shareholder's equity | | | |
| Common stock | 2,191 | | | 1,907 | |
| | | |
| | | |
| Retained earnings | 1,863 | | | 1,776 | |
| | | |
| | | |
| Total shareholder's equity | 4,054 | | | 3,683 | |
| | | |
| | | |
| Total liabilities and shareholder's equity | $ | 11,370 | | | $ | 10,634 | |
|
| | | | | | | |
| (In millions) | September 30, 2019 | | December 31, 2018 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | — |
| | $ | 35 |
|
| Accounts payable | 245 |
| | 295 |
|
| Accrued expenses | 165 |
| | 155 |
|
| Payables to affiliates | 51 |
| | 65 |
|
| Customer deposits | 120 |
| | 120 |
|
| Regulatory liabilities | 21 |
| | 77 |
|
| Other | 63 |
| | 27 |
|
| Total current liabilities | 665 |
| | 774 |
|
| Long-term debt | 3,270 |
| | 2,876 |
|
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 1,329 |
| | 1,222 |
|
| Asset retirement obligations | 22 |
| | 24 |
|
| Non-pension postretirement benefits obligations | 198 |
| | 201 |
|
| Regulatory liabilities | 1,158 |
| | 1,192 |
|
| Other | 112 |
| | 73 |
|
| Total deferred credits and other liabilities | 2,819 |
| | 2,712 |
|
| Total liabilities | 6,754 |
| | 6,362 |
|
| Commitments and contingencies |
| |
|
| Shareholder's equity | | | |
| Common stock | 1,818 |
| | 1,714 |
|
| Retained earnings | 1,732 |
| | 1,640 |
|
| Total shareholder's equity | 3,550 |
| | 3,354 |
|
| Total liabilities and shareholder's equity | $ | 10,304 |
| | $ | 9,716 |
|
See the Combined Notes to Consolidated Financial Statements
35
BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 | | | | |
| (In millions) | Common
Stock | | Retained
Earnings | | Total
Shareholder's
Equity | | | | |
| Balance, December 31, 2019 | $ | 1,907 | | | $ | 1,776 | | | $ | 3,683 | | | | | |
| Net income | — | | | 181 | | | 181 | | | | | |
| Common stock dividends | — | | | (62) | | | (62) | | | | | |
| Balance, March 31, 2020 | $ | 1,907 | | | $ | 1,895 | | | $ | 3,802 | | | | | |
| Net income | — | | | 39 | | | 39 | | | | | |
| Common stock dividends | — | | | (62) | | | (62) | | | | | |
| Contributions from parent | 26 | | | — | | | 26 | | | | | |
| Balance, June 30, 2020 | $ | 1,933 | | | $ | 1,872 | | | $ | 3,805 | | | | | |
| Net income | — | | | 53 | | | 53 | | | | | |
| Common stock dividends | — | | | (62) | | | (62) | | | | | |
| Contributions from parent | 258 | | | — | | | 258 | | | | | |
| Balance, September 30, 2020 | $ | 2,191 | | | $ | 1,863 | | | $ | 4,054 | | | | | |
| | | | | | | | | |
| Nine Months Ended September 30, 2019 | | | | |
| (In millions) | Common
Stock | | Retained
Earnings | | Total
Shareholder's
Equity | | | | |
| Balance, December 31, 2018 | $ | 1,714 | | | $ | 1,640 | | | $ | 3,354 | | | | | |
| Net income | — | | | 160 | | | 160 | | | | | |
| Common stock dividends | — | | | (56) | | | (56) | | | | | |
| Balance, March 31, 2019 | $ | 1,714 | | | $ | 1,744 | | | $ | 3,458 | | | | | |
| Net income | — | | | 45 | | | 45 | | | | | |
| Common stock dividends | — | | | (55) | | | (55) | | | | | |
| Balance, June 30, 2019 | $ | 1,714 | | | $ | 1,734 | | | $ | 3,448 | | | | | |
| Net income | — | | | 55 | | | 55 | | | | | |
| Common stock dividends | — | | | (57) | | | (57) | | | | | |
| Contributions from parent | 104 | | | — | | | 104 | | | | | |
| Balance, September 30, 2019 | $ | 1,818 | | | $ | 1,732 | | | $ | 3,550 | | | | | |
See the Combined Notes to Consolidated Financial Statements
36
|
| | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2018 | $ | 1,714 |
| | $ | 1,640 |
| | $ | 3,354 |
|
| Net income | — |
| | 160 |
| | 160 |
|
| Common stock dividends | — |
| | (56 | ) | | (56 | ) |
| Balance, March 31, 2019 | $ | 1,714 |
| | $ | 1,744 |
| | $ | 3,458 |
|
| Net income | — |
| | 45 |
| | 45 |
|
| Common stock dividends | — |
| | (55 | ) | | (55 | ) |
| Balance, June 30, 2019 | $ | 1,714 |
| | $ | 1,734 |
| | $ | 3,448 |
|
| Net income | — |
| | 55 |
| | 55 |
|
| Contributions from parent | 104 |
| | — |
| | 104 |
|
| Common stock dividends | — |
| | (57 | ) | | (57 | ) |
| Balance, September 30, 2019 | $ | 1,818 |
|
| $ | 1,732 |
| | $ | 3,550 |
|
| | | | | | |
| | Nine Months Ended September 30, 2018 |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2017 | $ | 1,605 |
| | $ | 1,536 |
| | $ | 3,141 |
|
| Net income | — |
| | 128 |
| | 128 |
|
| Common stock dividends | — |
| | (52 | ) | | (52 | ) |
| Balance, March 31, 2018 | $ | 1,605 |
| | $ | 1,612 |
| | $ | 3,217 |
|
| Net income | — |
| | 51 |
| | 51 |
|
| Common stock dividends | — |
| | (53 | ) | | (53 | ) |
| Balance, June 30, 2018 | $ | 1,605 |
| | $ | 1,610 |
| | $ | 3,215 |
|
| Net income | — |
| | 63 |
| | 63 |
|
| Contributions from parent | 18 |
| | — |
| | 18 |
|
| Common stock dividends | — |
| | (52 | ) | | (52 | ) |
| Balance, September 30, 2018 | $ | 1,623 |
| | $ | 1,621 |
| | $ | 3,244 |
|
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 | | 2020 | | 2019 |
| Operating revenues | | | | | | | |
| Electric operating revenues | $ | 1,308 | | | $ | 1,365 | | | $ | 3,440 | | | $ | 3,570 | |
| Natural gas operating revenues | 23 | | | 20 | | | 116 | | | 115 | |
| Revenues from alternative revenue programs | 31 | | | (9) | | | (15) | | | 4 | |
| Operating revenues from affiliates | 6 | | | 4 | | | 13 | | | 11 | |
| Total operating revenues | 1,368 | | | 1,380 | | | 3,554 | | | 3,700 | |
| Operating expenses | | | | | | | |
| Purchased power | 393 | | | 428 | | | 979 | | | 1,086 | |
| Purchased fuel | 7 | | | 8 | | | 49 | | | 51 | |
| Purchased power from affiliates | 106 | | | 83 | | | 288 | | | 254 | |
| Operating and maintenance | 237 | | | 254 | | | 702 | | | 706 | |
| Operating and maintenance from affiliates | 38 | | | 36 | | | 111 | | | 105 | |
| Depreciation and amortization | 200 | | | 193 | | | 585 | | | 562 | |
| Taxes other than income taxes | 121 | | | 122 | | | 343 | | | 342 | |
| Total operating expenses | 1,102 | | | 1,124 | | | 3,057 | | | 3,106 | |
| | | | | | | |
| Gain on sales of assets | 0 | | | 0 | | | 2 | | | 0 | |
| Operating income | 266 | | | 256 | | | 499 | | | 594 | |
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (67) | | | (66) | | | (201) | | | (197) | |
| | | | | | | |
| Other, net | 16 | | | 13 | | | 42 | | | 39 | |
| Total other income and (deductions) | (51) | | | (53) | | | (159) | | | (158) | |
| Income before income taxes | 215 | | | 203 | | | 340 | | | 436 | |
| Income taxes | (1) | | | 14 | | | (77) | | | 25 | |
| Equity in earnings of unconsolidated affiliate | 0 | | | 0 | | | 1 | | | 1 | |
| Net income | $ | 216 | | | $ | 189 | | | $ | 418 | | | $ | 412 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Comprehensive income | $ | 216 | | | $ | 189 | | | $ | 418 | | | $ | 412 | |
See the Combined Notes to Consolidated Financial Statements
37
|
| | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Operating revenues | | | | | | | |
| Electric operating revenues | $ | 1,365 |
| | $ | 1,340 |
| | $ | 3,570 |
| | $ | 3,541 |
|
| Natural gas operating revenues | 20 |
| | 23 |
| | 115 |
| | 129 |
|
| Revenues from alternative revenue programs | (9 | ) | | (5 | ) | | 4 |
| | 7 |
|
| Operating revenues from affiliates | 4 |
| | 3 |
| | 11 |
| | 11 |
|
| Total operating revenues | 1,380 |
| | 1,361 |
| | 3,700 |
| | 3,688 |
|
| Operating expenses | | | | | | | |
| Purchased power | 428 |
| | 415 |
| | 1,086 |
| | 1,077 |
|
| Purchased fuel | 8 |
| | 12 |
| | 51 |
| | 65 |
|
| Purchased power and fuel from affiliates | 83 |
| | 82 |
| | 254 |
| | 268 |
|
| Operating and maintenance | 254 |
| | 261 |
| | 706 |
| | 751 |
|
| Operating and maintenance from affiliates | 36 |
| | 31 |
| | 105 |
| | 106 |
|
| Depreciation and amortization | 193 |
| | 192 |
| | 562 |
| | 555 |
|
| Taxes other than income | 122 |
| | 123 |
| | 342 |
| | 343 |
|
| Total operating expenses | 1,124 |
| | 1,116 |
| | 3,106 |
| | 3,165 |
|
| Operating income | 256 |
| | 245 |
|
| 594 |
| | 523 |
|
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (66 | ) | | (65 | ) | | (197 | ) | | (193 | ) |
| Other, net | 13 |
| | 11 |
| | 39 |
| | 33 |
|
| Total other income and (deductions) | (53 | ) | | (54 | ) | | (158 | ) | | (160 | ) |
| Income before income taxes | 203 |
| | 191 |
| | 436 |
| | 363 |
|
| Income taxes | 14 |
| | 4 |
| | 25 |
| | 28 |
|
| Equity in earnings of unconsolidated affiliate | — |
| | — |
| | 1 |
| | 1 |
|
| Net income | $ | 189 |
| | $ | 187 |
| | $ | 412 |
| | $ | 336 |
|
| Comprehensive income | $ | 189 |
| | $ | 187 |
| | $ | 412 |
| | $ | 336 |
|
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | |
| Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 |
| Cash flows from operating activities | | | |
| Net income | $ | 418 | | | $ | 412 | |
| | | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation and amortization | 585 | | | 562 | |
| | | |
| | | |
| Deferred income taxes and amortization of investment tax credits | (99) | | | 8 | |
| | | |
| Other non-cash operating activities | 115 | | | 122 | |
| Changes in assets and liabilities: | | | |
| Accounts receivable | (121) | | | (64) | |
| Receivables from and payables to affiliates, net | (26) | | | 1 | |
| Inventories | (2) | | | (36) | |
| Accounts payable and accrued expenses | 57 | | | 0 | |
| | | |
| | | |
| Income taxes | (14) | | | (11) | |
| Pension and non-pension postretirement benefit contributions | (35) | | | (15) | |
| Other assets and liabilities | (61) | | | (102) | |
| Net cash flows provided by operating activities | 817 | | | 877 | |
| Cash flows from investing activities | | | |
| Capital expenditures | (1,072) | | | (1,006) | |
| | | |
| | | |
| | | |
| | | |
| Other investing activities | 3 | | | 3 | |
| Net cash flows used in investing activities | (1,069) | | | (1,003) | |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | (208) | | | 78 | |
| | | |
| Repayments of short-term borrowings with maturities greater than 90 days | 0 | | | (125) | |
| Issuance of long-term debt | 601 | | | 410 | |
| Retirement of long-term debt | (119) | | | (130) | |
| Changes in Exelon intercompany money pool | 9 | | | 10 | |
| | | |
| | | |
| | | |
| Distributions to member | (451) | | | (429) | |
| Contributions from member | 493 | | | 283 | |
| | | |
| | | |
| Other financing activities | (10) | | | (5) | |
| Net cash flows provided by financing activities | 315 | | | 92 | |
| Increase (decrease) in cash, cash equivalents, and restricted cash | 63 | | | (34) | |
| Cash, cash equivalents, and restricted cash at beginning of period | 181 | | | 186 | |
| Cash, cash equivalents, and restricted cash at end of period | $ | 244 | | | $ | 152 | |
| | | |
| Supplemental cash flow information | | | |
| Decrease in capital expenditures not paid | $ | (5) | | | $ | (62) | |
| | | |
| | | |
See the Combined Notes to Consolidated Financial Statements
38
|
| | | | | | | |
| | Nine Months Ended
September 30, |
| (In millions) | 2019 | | 2018 |
| Cash flows from operating activities | | |
|
| Net income | $ | 412 |
| | $ | 336 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation and amortization | 562 |
| | 555 |
|
| Deferred income taxes and amortization of investment tax credits | 8 |
| | 50 |
|
| Other non-cash operating activities | 122 |
| | 109 |
|
| Changes in assets and liabilities: | | | |
| Accounts receivable | (64 | ) | | (89 | ) |
| Receivables from and payables to affiliates, net | 1 |
| | 10 |
|
| Inventories | (36 | ) | | — |
|
| Accounts payable and accrued expenses | — |
| | 115 |
|
| Income taxes | (11 | ) | | (31 | ) |
| Pension and non-pension postretirement benefit contributions | (15 | ) | | (66 | ) |
| Other assets and liabilities | (102 | ) | | (144 | ) |
| Net cash flows provided by operating activities | 877 |
| | 845 |
|
| Cash flows from investing activities | | | |
| Capital expenditures | (1,006 | ) | | (988 | ) |
| Other investing activities | 3 |
| | 2 |
|
| Net cash flows used in investing activities | (1,003 | ) |
| (986 | ) |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | 78 |
| | (141 | ) |
| Proceeds from short-term borrowings with maturities greater than 90 days | — |
| | 125 |
|
| Repayments of short-term borrowings with maturities greater than 90 days | (125 | ) | | — |
|
| Issuance of long-term debt | 410 |
| | 300 |
|
| Retirement of long-term debt | (130 | ) | | (33 | ) |
| Change in Exelon intercompany money pool | 10 |
| | 10 |
|
| Distributions to member | (429 | ) | | (232 | ) |
| Contributions from member | 283 |
| | 237 |
|
| Other financing activities | (5 | ) | | (6 | ) |
| Net cash flows provided by financing activities | 92 |
| | 260 |
|
| (Decrease) increase in cash, cash equivalents and restricted cash | (34 | ) | | 119 |
|
| Cash, cash equivalents and restricted cash at beginning of period | 186 |
| | 95 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 152 |
| | $ | 214 |
|
| | | | |
| Supplemental cash flow information | | | |
| (Decrease) increase in capital expenditures not paid | $ | (62 | ) | | $ | 54 |
|
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 196 | | | $ | 131 | |
| Restricted cash and cash equivalents | 38 | | | 36 | |
| Accounts receivable | | | |
| Customer accounts receivable | 584 | | 516 |
| Customer allowance for credit losses | (89) | | (37) |
| Customer accounts receivable, net | 495 | | | 479 | |
| Other accounts receivable | 244 | | 190 |
| Other allowance for credit losses | (32) | | (16) |
| Other accounts receivable, net | 212 | | | 174 | |
| | | |
| Receivables from affiliates | 0 | | | 1 | |
| | | |
| | | |
| Inventories, net | | | |
| Fossil fuel | 7 | | | 8 | |
| Materials and supplies | 194 | | | 190 | |
| | | |
| | | |
| Regulatory assets | 440 | | | 412 | |
| | | |
| Other | 52 | | | 49 | |
| Total current assets | 1,634 | | | 1,480 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $1,692 and $1,213 as of September 30, 2020 and December 31, 2019, respectively) | 14,954 | | | 14,296 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 1,972 | | | 2,061 | |
| Investments | 138 | | | 135 | |
| Goodwill | 4,005 | | | 4,005 | |
| | | |
| | | |
| Prepaid pension asset | 381 | | | 406 | |
| | | |
| Deferred income taxes | 10 | | | 13 | |
| Other | 300 | | | 323 | |
| Total deferred debits and other assets | 6,806 | | | 6,943 | |
Total assets(a) | $ | 23,394 | | | $ | 22,719 | |
See the Combined Notes to Consolidated Financial Statements
39
|
| | | | | | | |
| (In millions) | September 30, 2019 | | December 31, 2018 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 99 |
| | $ | 124 |
|
| Restricted cash and cash equivalents | 38 |
| | 43 |
|
| Accounts receivable, net | | | |
| Customer (net of allowance for uncollectible accounts of $41 and $50 as of September 30, 2019 and December 31, 2018, respectively) | 512 |
| | 453 |
|
| Other (net of allowance for uncollectible accounts of $16 and $3 as of September 30, 2019 and December 31, 2018, respectively) | 189 |
| | 177 |
|
| Inventories, net | | | |
| Fossil Fuel | 8 |
| | 9 |
|
| Materials and supplies | 203 |
| | 163 |
|
| Regulatory assets | 479 |
| | 489 |
|
| Other | 50 |
| | 75 |
|
| Total current assets | 1,578 |
|
| 1,533 |
|
| Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,124 and $841 as of September 30, 2019 and December 31, 2018, respectively) | 13,968 |
| | 13,446 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 2,095 |
| | 2,312 |
|
| Investments | 135 |
| | 130 |
|
| Goodwill | 4,005 |
| | 4,005 |
|
| Prepaid pension asset | 426 |
| | 486 |
|
| Deferred income taxes | 13 |
| | 12 |
|
| Other | 356 |
| | 60 |
|
| Total deferred debits and other assets | 7,030 |
|
| 7,005 |
|
Total assets(a) | $ | 22,576 |
|
| $ | 21,984 |
|
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | (In millions) | September 30, 2019 | | December 31, 2018 | (In millions) | September 30, 2020 | | December 31, 2019 |
| LIABILITIES AND MEMBER'S EQUITY | | | | LIABILITIES AND MEMBER'S EQUITY | | | |
| Current liabilities | | | | Current liabilities | |
| Short-term borrowings | $ | 132 |
| | $ | 179 |
| Short-term borrowings | $ | 0 | | | $ | 208 | |
| Long-term debt due within one year | 118 |
| | 125 |
| Long-term debt due within one year | 349 | | | 103 | |
| Accounts payable | 416 |
| | 496 |
| Accounts payable | 507 | | | 462 | |
| Accrued expenses | 279 |
| | 256 |
| Accrued expenses | 279 | | | 296 | |
| Payables to affiliates | 95 |
| | 94 |
| Payables to affiliates | 71 | | | 98 | |
| Borrowings from Exelon intercompany money pool | 10 |
| | — |
| Borrowings from Exelon intercompany money pool | 21 | | | 12 | |
| | Customer deposits | 118 |
| | 116 |
| Customer deposits | 111 | | | 117 | |
| Regulatory liabilities | 78 |
| | 84 |
| Regulatory liabilities | 143 | | | 70 | |
| Unamortized energy contract liabilities | 117 |
| | 119 |
| Unamortized energy contract liabilities | 98 | | | 115 | |
| | Other | 152 |
| | 123 |
| Other | 144 | | | 131 | |
| Total current liabilities | 1,515 |
| | 1,592 |
| Total current liabilities | 1,723 | | | 1,612 | |
| Long-term debt | 6,376 |
| | 6,134 |
| Long-term debt | 6,671 | | | 6,460 | |
| Deferred credits and other liabilities | | | | Deferred credits and other liabilities | |
| Deferred income taxes and unamortized investment tax credits | 2,289 |
| | 2,146 |
| Deferred income taxes and unamortized investment tax credits | 2,409 | | | 2,278 | |
| Asset retirement obligations | 57 |
| | 52 |
| Asset retirement obligations | 58 | | | 57 | |
| Non-pension postretirement benefit obligations | 99 |
| | 103 |
| Non-pension postretirement benefit obligations | 85 | | | 93 | |
| Regulatory liabilities | 1,725 |
| | 1,864 |
| Regulatory liabilities | 1,471 | | | 1,707 | |
| | Unamortized energy contract liabilities | 357 |
| | 442 |
| Unamortized energy contract liabilities | 258 | | | 327 | |
| Other | 610 |
| | 369 |
| Other | 650 | | | 577 | |
| Total deferred credits and other liabilities | 5,137 |
| | 4,976 |
| Total deferred credits and other liabilities | 4,931 | | | 5,039 | |
Total liabilities(a) | 13,028 |
| | 12,702 |
| Total liabilities(a) | 13,325 | | | 13,111 | |
| Commitments and contingencies |
| |
| Commitments and contingencies | | | |
| | Member's equity | | | | Member's equity | |
| Membership interest | 9,503 |
| | 9,220 |
| Membership interest | 10,112 | | | 9,618 | |
| Undistributed earnings | 45 |
| | 62 |
| |
| | Undistributed losses | | Undistributed losses | (43) | | | (10) | |
| | Total member's equity | 9,548 |
|
| 9,282 |
| Total member's equity | 10,069 | | | 9,608 | |
| Total liabilities and member's equity | $ | 22,576 |
|
| $ | 21,984 |
| Total liabilities and member's equity | $ | 23,394 | | | $ | 22,719 | |
__________
| |
(a) | PHI’s consolidated total assets include $22 million and $33 million at September 30, 2019 and December 31, 2018, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $50 million and $69 million at September 30, 2019 and December 31, 2018, 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 $20 million and $20 million at September 30, 2020 and December 31, 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 $32 million and $44 million at September 30, 2020 and December 31, 2019, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 16 — Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
40
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| (In millions) | Membership Interest | | Undistributed Earnings (Losses) | | | | Member's Equity |
| Balance, December 31, 2019 | $ | 9,618 | | | $ | (10) | | | | | $ | 9,608 | |
| Net income | — | | | 108 | | | | | 108 | |
| Distributions to member | — | | | (134) | | | | | (134) | |
| Contributions from member | 144 | | | — | | | | | 144 | |
| Balance, March 31, 2020 | $ | 9,762 | | | $ | (36) | | | | | $ | 9,726 | |
| Net income | — | | | 94 | | | | | 94 | |
| Distributions to member | — | | | (134) | | | | | (134) | |
| Contributions from member | 215 | | | — | | | | | 215 | |
| Balance, June 30, 2020 | $ | 9,977 | | | $ | (76) | | | | | $ | 9,901 | |
| Net income | — | | | 216 | | | | | 216 | |
| Distributions to member | — | | | (183) | | | | | (183) | |
| Contributions from member | 135 | | | — | | | | | 135 | |
| | | | | | | |
| Balance, September 30, 2020 | $ | 10,112 | | | $ | (43) | | | | | $ | 10,069 | |
| | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 |
| (In millions) | Membership Interest | | Undistributed Earnings (Losses) | | | | Member's Equity |
| Balance, December 31, 2018 | $ | 9,220 | | | $ | 62 | | | | | $ | 9,282 | |
| Net income | — | | | 117 | | | | | 117 | |
| Distributions to member | — | | | (128) | | | | | (128) | |
| Contributions from member | 19 | | | — | | | | | 19 | |
| Balance, March 31, 2019 | $ | 9,239 | | | $ | 51 | | | | | $ | 9,290 | |
| Net income | — | | | 106 | | | | | 106 | |
| Distributions to member | — | | | (88) | | | | | (88) | |
| Contributions from member | 264 | | | — | | | | | 264 | |
| Balance, June 30, 2019 | $ | 9,503 | | | $ | 69 | | | | | $ | 9,572 | |
| Net income | — | | | 189 | | | | | 189 | |
| Distributions to member | — | | | (213) | | | | | (213) | |
| | | | | | | |
| Balance, September 30, 2019 | $ | 9,503 | | | $ | 45 | | | | | $ | 9,548 | |
| | | | | | | |
See the Combined Notes to Consolidated Financial Statements
41
|
| | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 |
| (In millions) | Membership Interest | | Undistributed Earnings (Losses) | | Member's Equity |
| Balance, December 31, 2018 | $ | 9,220 |
| | $ | 62 |
| | $ | 9,282 |
|
| Net income | — |
| | 117 |
| | 117 |
|
| Distributions to member | — |
| | (128 | ) | | (128 | ) |
| Contributions from member | 19 |
| | — |
| | 19 |
|
| Balance, March 31, 2019 | $ | 9,239 |
| | $ | 51 |
| | $ | 9,290 |
|
| Net income | — |
|
| 106 |
| | 106 |
|
| Distributions to member | — |
|
| (88 | ) | | (88 | ) |
| Contributions from member | 264 |
|
| — |
| | 264 |
|
| Balance, June 30, 2019 | $ | 9,503 |
| | $ | 69 |
| | $ | 9,572 |
|
| Net income | — |
|
| 189 |
| | 189 |
|
| Distributions to member | — |
|
| (213 | ) | | (213 | ) |
| Balance, September 30, 2019 | $ | 9,503 |
| | $ | 45 |
| | $ | 9,548 |
|
|
| | | | | | | | | | | |
| | Nine Months Ended September 30, 2018 |
| (In millions) | Membership Interest | | Undistributed Earnings (Losses) | | Member's Equity |
| Balance, December 31, 2017 | $ | 8,835 |
| | $ | (10 | ) | | $ | 8,825 |
|
| Net income | — |
| | 65 |
| | 65 |
|
| Distributions to member | — |
| | (71 | ) | | (71 | ) |
| Balance, March 31, 2018 | $ | 8,835 |
| | $ | (16 | ) | | $ | 8,819 |
|
| Net income | — |
| | 84 |
| | 84 |
|
| Distributions to member | — |
| | (38 | ) | | (38 | ) |
| Contributions from member | 235 |
| | — |
| | 235 |
|
| Balance, June 30, 2018 | $ | 9,070 |
| | $ | 30 |
| | $ | 9,100 |
|
| Net income | — |
|
| 187 |
|
| 187 |
|
| Distribution to member | — |
|
| (123 | ) |
| (123 | ) |
| Contribution from parent | 2 |
|
| — |
|
| 2 |
|
| Balance, September 30, 2018 | $ | 9,072 |
|
| $ | 94 |
|
| $ | 9,166 |
|
POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
September 30, | | Nine Months Ended
September 30, | | |
| (In millions) | 2020 | | 2019 | | 2020 | | 2019 | | | | |
| Operating revenues | | | | | | | | | | | |
| Electric operating revenues | $ | 590 | | | $ | 643 | | | $ | 1,624 | | | $ | 1,733 | | | | | |
| Revenues from alternative revenue programs | 18 | | | (3) | | | 20 | | | 10 | | | | | |
| Operating revenues from affiliates | 3 | | | 2 | | | 6 | | | 5 | | | | | |
| Total operating revenues | 611 | | | 642 | | | 1,650 | | | 1,748 | | | | | |
| Operating expenses | | | | | | | | | | | |
| Purchased power | 83 | | | 116 | | | 248 | | | 325 | | | | | |
| Purchased power from affiliate | 80 | | | 65 | | | 219 | | | 188 | | | | | |
| Operating and maintenance | 57 | | | 85 | | | 184 | | | 208 | | | | | |
| Operating and maintenance from affiliates | 49 | | | 50 | | | 152 | | | 156 | | | | | |
| Depreciation and amortization | 96 | | | 95 | | | 282 | | | 281 | | | | | |
| Taxes other than income taxes | 100 | | | 104 | | | 279 | | | 286 | | | | | |
| Total operating expenses | 465 | | | 515 | | | 1,364 | | | 1,444 | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Operating income | 146 | | | 127 | | | 286 | | | 304 | | | | | |
| Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | (35) | | | (33) | | | (103) | | | (100) | | | | | |
| | | | | | | | | | | |
| Other, net | 10 | | | 9 | | | 28 | | | 22 | | | | | |
| Total other income and (deductions) | (25) | | | (24) | | | (75) | | | (78) | | | | | |
| Income before income taxes | 121 | | | 103 | | | 211 | | | 226 | | | | | |
| Income taxes | 3 | | | 5 | | | (16) | | | 9 | | | | | |
| | | | | | | | | | | |
| Net income | $ | 118 | | | $ | 98 | | | $ | 227 | | | $ | 217 | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Comprehensive income | $ | 118 | | | $ | 98 | | | $ | 227 | | | $ | 217 | | | | | |
See the Combined Notes to Consolidated Financial Statements
42
|
| | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, |
| Nine Months Ended
September 30, |
| (In millions) | 2019 |
| 2018 |
| 2019 |
| 2018 |
| Operating revenues | | | | | | | |
| Electric operating revenues | $ | 643 |
| | $ | 630 |
| | $ | 1,733 |
| | $ | 1,697 |
|
| Revenues from alternative revenue programs | (3 | ) | | (4 | ) | | 10 |
| | 6 |
|
| Operating revenues from affiliates | 2 |
| | 2 |
| | 5 |
| | 5 |
|
| Total operating revenues | 642 |
| | 628 |
| | 1,748 |
| | 1,708 |
|
| Operating expenses | | | | | | | |
| Purchased power | 116 |
| | 131 |
| | 325 |
| | 354 |
|
| Purchased power from affiliates | 65 |
| | 46 |
| | 188 |
| | 143 |
|
| Operating and maintenance | 85 |
| | 84 |
| | 208 |
| | 216 |
|
| Operating and maintenance from affiliates | 50 |
| | 52 |
| | 156 |
| | 167 |
|
| Depreciation and amortization | 95 |
| | 99 |
| | 281 |
| | 286 |
|
| Taxes other than income | 104 |
| | 104 |
| | 286 |
| | 288 |
|
| Total operating expenses | 515 |
| | 516 |
| | 1,444 |
| | 1,454 |
|
| Operating income | 127 |
| | 112 |
| | 304 |
| | 254 |
|
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (33 | ) | | (32 | ) | | (100 | ) | | (96 | ) |
| Other, net | 9 |
| | 7 |
| | 22 |
| | 23 |
|
| Total other income and (deductions) | (24 | ) | | (25 | ) | | (78 | ) | | (73 | ) |
| Income before income taxes | 103 |
| | 87 |
| | 226 |
| | 181 |
|
| Income taxes | 5 |
| | (2 | ) | | 9 |
| | 7 |
|
| Net income | $ | 98 |
| | $ | 89 |
| | $ | 217 |
| | $ | 174 |
|
| Comprehensive income | $ | 98 |
| | $ | 89 |
| | $ | 217 |
| | $ | 174 |
|
POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | |
| Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 |
| Cash flows from operating activities | | | |
| Net income | $ | 227 | | | $ | 217 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation and amortization | 282 | | | 281 | |
| | | |
| Deferred income taxes and amortization of investment tax credits | (36) | | | 12 | |
| | | |
| Other non-cash operating activities | 6 | | | 43 | |
| Changes in assets and liabilities: | | | |
| Accounts receivable | (61) | | | (49) | |
| Receivables from and payables to affiliates, net | (23) | | | 4 | |
| Inventories | 2 | | | (23) | |
| Accounts payable and accrued expenses | 36 | | | (12) | |
| Income taxes | (11) | | | (23) | |
| Pension and non-pension postretirement benefit contributions | (8) | | | (10) | |
| Other assets and liabilities | 15 | | | (55) | |
| Net cash flows provided by operating activities | 429 | | | 385 | |
| Cash flows from investing activities | | | |
| Capital expenditures | (512) | | | (455) | |
| | | |
| | | |
| | | |
| Changes in PHI intercompany money pool | (117) | | | 0 | |
| Other investing activities | (3) | | | 2 | |
| Net cash flows used in investing activities | (632) | | | (453) | |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | (82) | | | (28) | |
| Issuance of long-term debt | 300 | | | 260 | |
| Retirement of long-term debt | (2) | | | (118) | |
| | | |
| Dividends paid on common stock | (174) | | | (173) | |
| Contributions from parent | 262 | | | 129 | |
| | | |
| | | |
| Other financing activities | (6) | | | (3) | |
| Net cash flows provided by financing activities | 298 | | | 67 | |
| Increase (decrease) in cash, cash equivalents, and restricted cash | 95 | | | (1) | |
| Cash, cash equivalents, and restricted cash at beginning of period | 63 | | | 53 | |
| Cash, cash equivalents, and restricted cash at end of period | $ | 158 | | | $ | 52 | |
| | | |
| Supplemental cash flow information | | | |
| Decrease in capital expenditures not paid | $ | (23) | | | $ | (7) | |
| | | |
| | | |
See the Combined Notes to Consolidated Financial Statements
43
|
| | | | | | | |
| | Nine Months Ended
September 30, |
| (In millions) | 2019 | | 2018 |
| Cash flows from operating activities | | | |
| Net income | $ | 217 |
| | $ | 174 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation and amortization | 281 |
| | 286 |
|
| Deferred income taxes and amortization of investment tax credits | 12 |
| | (5 | ) |
| Other non-cash operating activities | 43 |
| | 42 |
|
| Changes in assets and liabilities: | | | |
| Accounts receivable | (49 | ) | | (36 | ) |
| Receivables from and payables to affiliates, net | 4 |
| | (9 | ) |
| Inventories | (23 | ) | | 6 |
|
| Accounts payable and accrued expenses | (12 | ) | | 104 |
|
| Income taxes | (23 | ) | | (18 | ) |
| Pension and non-pension postretirement benefit contributions | (10 | ) | | (11 | ) |
| Other assets and liabilities | (55 | ) | | (137 | ) |
| Net cash flows provided by operating activities | 385 |
| | 396 |
|
| Cash flows from investing activities | | | |
| Capital expenditures | (455 | ) | | (475 | ) |
| Other investing activities | 2 |
| | 3 |
|
| Net cash flows used in investing activities | (453 | ) | | (472 | ) |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | (28 | ) | | 38 |
|
| Issuance of long-term debt | 260 |
| | 100 |
|
| Retirement of long-term debt | (118 | ) | | (8 | ) |
| Dividends paid on common stock | (173 | ) | | (128 | ) |
| Contributions from parent | 129 |
| | 85 |
|
| Other financing activities | (3 | ) | | (4 | ) |
| Net cash flows provided by financing activities | 67 |
| | 83 |
|
| (Decrease) increase in cash, cash equivalents and restricted cash | (1 | ) | | 7 |
|
| Cash, cash equivalents and restricted cash at beginning of period | 53 |
| | 40 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 52 |
| | $ | 47 |
|
| | | | |
| Supplemental cash flow information | | | |
| (Decrease) increase in capital expenditures not paid | $ | (7 | ) | | $ | 15 |
|
POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 125 | | | $ | 30 | |
| Restricted cash and cash equivalents | 33 | | | 33 | |
| Accounts receivable | | | |
| Customer accounts receivable | 278 | | 244 |
| Customer allowance for credit losses | (35) | | (13) |
| Customer accounts receivable, net | 243 | | | 231 | |
| Other accounts receivable | 129 | | 98 |
| Other allowance for credit losses | (13) | | (7) |
| Other accounts receivable, net | 116 | | | 91 | |
| | | |
| | | |
| Receivable from PHI intercompany money pool | 117 | | | 0 | |
| | | |
| Inventories, net | 110 | | | 112 | |
| | | |
| | | |
| | | |
| Regulatory assets | 200 | | | 188 | |
| | | |
| Other | 13 | | | 11 | |
| Total current assets | 957 | | | 696 | |
| Property, plant, and equipment (net of accumulated depreciation and amortization of $3,651 and $3,517 as of September 30, 2020 and December 31, 2019, respectively) | 7,236 | | | 6,909 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 573 | | | 584 | |
| Investments | 113 | | | 110 | |
| | | |
| | | |
| | | |
| Prepaid pension asset | 287 | | | 296 | |
| | | |
| Other | 61 | | | 66 | |
| Total deferred debits and other assets | 1,034 | | | 1,056 | |
| Total assets | $ | 9,227 | | | $ | 8,661 | |
See the Combined Notes to Consolidated Financial Statements
44
|
| | | | | | | |
| (In millions) | September 30, 2019 |
| December 31, 2018 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 18 |
| | $ | 16 |
|
| Restricted cash and cash equivalents | 34 |
| | 37 |
|
| Accounts receivable, net | | | |
| Customer (net of allowance for uncollectible accounts of $16 and $20 as of September 30, 2019 and December 31, 2018, respectively) | 258 |
| | 225 |
|
| Other (net of allowance for uncollectible accounts of $8 and $1 as of September 30, 2019 and December 31, 2018, respectively) | 114 |
| | 81 |
|
| Receivables from affiliates | — |
| | 1 |
|
| Inventories, net | 118 |
| | 93 |
|
| Regulatory assets | 252 |
| | 270 |
|
| Other | 12 |
| | 37 |
|
| Total current assets | 806 |
|
| 760 |
|
| Property, plant and equipment, net (net of accumulated depreciation and amortization of $3,473 and $3,354 as of September 30, 2019 and December 31, 2018, respectively) | 6,734 |
| | 6,460 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 577 |
| | 643 |
|
| Investments | 109 |
| | 105 |
|
| Prepaid pension asset | 301 |
| | 316 |
|
| Other | 76 |
| | 15 |
|
| Total deferred debits and other assets | 1,063 |
|
| 1,079 |
|
| Total assets | $ | 8,603 |
|
| $ | 8,299 |
|
POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 0 | | | $ | 82 | |
| Long-term debt due within one year | 3 | | | 2 | |
| Accounts payable | 206 | | | 195 | |
| Accrued expenses | 144 | | | 156 | |
| Payables to affiliates | 43 | | | 66 | |
| | | |
| | | |
| | | |
| Customer deposits | 54 | | | 57 | |
| Regulatory liabilities | 49 | | | 8 | |
| Merger related obligation | 39 | | | 39 | |
| Current portion of DC PLUG obligation | 30 | | | 30 | |
| Other | 29 | | | 22 | |
| Total current liabilities | 597 | | | 657 | |
| Long-term debt | 3,161 | | | 2,862 | |
| | | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 1,194 | | | 1,131 | |
| Asset retirement obligations | 38 | | | 41 | |
| | | |
| Non-pension postretirement benefit obligations | 14 | | | 20 | |
| | | |
| | | |
| | | |
| | | |
| Regulatory liabilities | 647 | | | 746 | |
| Other | 354 | | | 297 | |
| Total deferred credits and other liabilities | 2,247 | | | 2,235 | |
| Total liabilities | 6,005 | | | 5,754 | |
| Commitments and contingencies | | | |
| Shareholder's equity | | | |
| | | |
| Common stock | 2,058 | | | 1,796 | |
| | | |
| | | |
| Retained earnings | 1,164 | | | 1,111 | |
| | | |
| Total shareholder's equity | 3,222 | | | 2,907 | |
| Total liabilities and shareholder's equity | $ | 9,227 | | | $ | 8,661 | |
See the Combined Notes to Consolidated Financial Statements
45
|
| | | | | | | |
| (In millions) | September 30, 2019 | | December 31, 2018 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 12 |
| | $ | 40 |
|
| Long-term debt due within one year | 8 |
| | 15 |
|
| Accounts payable | 177 |
| | 214 |
|
| Accrued expenses | 144 |
| | 126 |
|
| Payables to affiliates | 65 |
| | 62 |
|
| Customer deposits | 56 |
| | 54 |
|
| Regulatory liabilities | 9 |
| | 7 |
|
| Merger related obligation | 38 |
| | 38 |
|
| Current portion of DC PLUG obligation | 30 |
| | 30 |
|
| Other | 25 |
| | 42 |
|
| Total current liabilities | 564 |
|
| 628 |
|
| Long-term debt | 2,852 |
| | 2,704 |
|
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 1,150 |
| | 1,064 |
|
| Asset retirement obligations | 41 |
| | 37 |
|
| Non-pension postretirement benefit obligations | 23 |
| | 29 |
|
| Regulatory liabilities | 749 |
| | 822 |
|
| Other | 311 |
| | 275 |
|
| Total deferred credits and other liabilities | 2,274 |
|
| 2,227 |
|
| Total liabilities | 5,690 |
|
| 5,559 |
|
| Commitments and contingencies |
| |
|
| Shareholder's equity | | | |
| Common stock | 1,765 |
| | 1,636 |
|
| Retained earnings | 1,148 |
| | 1,104 |
|
| Total shareholder's equity | 2,913 |
| | 2,740 |
|
| Total liabilities and shareholder's equity | $ | 8,603 |
| | $ | 8,299 |
|
POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| (In millions) | Common Stock | | | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2019 | $ | 1,796 | | | | | $ | 1,111 | | | $ | 2,907 | |
| Net income | — | | | | | 52 | | | 52 | |
| Common stock dividends | — | | | | | (28) | | | (28) | |
| Contributions from parent | 137 | | | | | — | | | 137 | |
| Balance, March 31, 2020 | $ | 1,933 | | | | | $ | 1,135 | | | $ | 3,068 | |
| Net income | — | | | | | 57 | | | 57 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Common stock dividends | — | | | | | (73) | | | (73) | |
| | | | | | | |
| Balance, June 30, 2020 | $ | 1,933 | | | | | $ | 1,119 | | | $ | 3,052 | |
| Net income | — | | | | | 118 | | | 118 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Common stock dividends | — | | | | | (73) | | | (73) | |
| Contributions from parent | 125 | | | | | — | | | 125 | |
| Balance, September 30, 2020 | $ | 2,058 | | | | | $ | 1,164 | | | $ | 3,222 | |
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 |
| (In millions) | Common Stock | | | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2018 | $ | 1,636 | | | | | $ | 1,104 | | | $ | 2,740 | |
| Net income | — | | | | | 55 | | | 55 | |
| Common stock dividends | — | | | | | (24) | | | (24) | |
| Contributions from parent | 14 | | | | | — | | | 14 | |
| Balance, March 31, 2019 | $ | 1,650 | | | | | $ | 1,135 | | | $ | 2,785 | |
| Net income | — | | | | | 64 | | | 64 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Common stock dividends | — | | | | | (48) | | | (48) | |
| Contributions from parent | 115 | | | | | — | | | 115 | |
| Balance, June 30, 2019 | $ | 1,765 | | | | | $ | 1,151 | | | $ | 2,916 | |
| Net income | — | | | | | 98 | | | 98 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Common stock dividends | — | | | | | (101) | | | (101) | |
| | | | | | | |
| Balance, September 30, 2019 | $ | 1,765 | | | | | $ | 1,148 | | | $ | 2,913 | |
See the Combined Notes to Consolidated Financial Statements
46
|
| | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2018 | $ | 1,636 |
| | $ | 1,104 |
| | $ | 2,740 |
|
| Net income | — |
| | 55 |
| | 55 |
|
| Common stock dividends | — |
| | (24 | ) | | (24 | ) |
| Contributions from parent | 14 |
| | — |
| | 14 |
|
| Balance, March 31, 2019 | $ | 1,650 |
| | $ | 1,135 |
| | $ | 2,785 |
|
| Net income | — |
| | 64 |
| | 64 |
|
| Common stock dividends | — |
| | (48 | ) | | (48 | ) |
| Contributions from parent | 115 |
| | — |
| | 115 |
|
| Balance, June 30, 2019 | $ | 1,765 |
| | $ | 1,151 |
| | $ | 2,916 |
|
| Net income | — |
| | 98 |
| | 98 |
|
| Common stock dividends | — |
| | (101 | ) | | (101 | ) |
| Balance, September 30, 2019 | $ | 1,765 |
|
| $ | 1,148 |
|
| $ | 2,913 |
|
|
| | | | | | | | | | | |
| | Nine Months Ended September 30, 2018 |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2017 | $ | 1,470 |
| | $ | 1,063 |
| | $ | 2,533 |
|
| Net income | — |
| | 31 |
| | 31 |
|
| Common stock dividends | — |
| | (25 | ) | | (25 | ) |
| Balance, March 31, 2018 | $ | 1,470 |
| | $ | 1,069 |
| | $ | 2,539 |
|
| Net income | — |
| | 54 |
| | 54 |
|
| Common stock dividends | — |
| | (25 | ) | | (25 | ) |
| Contributions from parent | 85 |
| | — |
| | 85 |
|
| Balance, June 30, 2018 | $ | 1,555 |
| | $ | 1,098 |
| | $ | 2,653 |
|
| Net income | — |
| | 89 |
| | 89 |
|
| Common stock dividends | — |
| | (78 | ) | | (78 | ) |
| Balance, September 30, 2018 | $ | 1,555 |
| | $ | 1,109 |
| | $ | 2,664 |
|
DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 | | 2020 | | 2019 |
| Operating revenues | | | | | | | |
| Electric operating revenues | $ | 303 | | | $ | 304 | | | $ | 846 | | | $ | 872 | |
| Natural gas operating revenues | 23 | | | 20 | | | 116 | | | 116 | |
| Revenues from alternative revenue programs | 8 | | | (6) | | | (15) | | | (6) | |
| Operating revenues from affiliates | 3 | | | 1 | | | 7 | | | 5 | |
| Total operating revenues | 337 | | | 319 | | | 954 | | | 987 | |
| Operating expenses | | | | | | | |
| Purchased power | 103 | | | 105 | | | 270 | | | 298 | |
| Purchased fuel | 7 | | | 8 | | | 49 | | | 51 | |
| Purchased power from affiliates | 21 | | | 14 | | | 60 | | | 50 | |
| Operating and maintenance | 64 | | | 43 | | | 160 | | | 127 | |
| Operating and maintenance from affiliates | 37 | | | 37 | | | 112 | | | 113 | |
| Depreciation and amortization | 48 | | | 46 | | | 143 | | | 138 | |
| Taxes other than income taxes | 16 | | | 15 | | | 49 | | | 43 | |
| Total operating expenses | 296 | | | 268 | | | 843 | | | 820 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Operating income | 41 | | | 51 | | | 111 | | | 167 | |
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (15) | | | (15) | | | (47) | | | (45) | |
| Other, net | 2 | | | 2 | | | 7 | | | 10 | |
| Total other income and (deductions) | (13) | | | (13) | | | (40) | | | (35) | |
| Income before income taxes | 28 | | | 38 | | | 71 | | | 132 | |
| Income taxes | 1 | | | 5 | | | (20) | | | 16 | |
| | | | | | | |
| Net income | $ | 27 | | | $ | 33 | | | $ | 91 | | | $ | 116 | |
| Comprehensive income | $ | 27 | | | $ | 33 | | | $ | 91 | | | $ | 116 | |
See the Combined Notes to Consolidated Financial Statements
47
|
| | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, |
| Nine Months Ended
September 30, |
| (In millions) | 2019 |
| 2018 |
| 2019 |
| 2018 |
| Operating revenues | | | | | | | |
| Electric operating revenues | $ | 304 |
| | $ | 302 |
| | $ | 872 |
| | $ | 861 |
|
| Natural gas operating revenues | 20 |
| | 24 |
| | 116 |
| | 129 |
|
| Revenues from alternative revenue programs | (6 | ) | | — |
| | (6 | ) | | 5 |
|
| Operating revenues from affiliates | 1 |
| | 2 |
| | 5 |
| | 6 |
|
| Total operating revenues | 319 |
|
| 328 |
|
| 987 |
|
| 1,001 |
|
| Operating expenses | | | | | | | |
| Purchased power | 105 |
| | 96 |
| | 298 |
| | 258 |
|
| Purchased fuel | 8 |
| | 11 |
| | 51 |
| | 64 |
|
| Purchased power from affiliate | 14 |
| | 26 |
| | 50 |
| | 103 |
|
| Operating and maintenance | 43 |
| | 44 |
| | 127 |
| | 137 |
|
| Operating and maintenance from affiliates | 37 |
| | 38 |
| | 113 |
| | 119 |
|
| Depreciation and amortization | 46 |
| | 47 |
| | 138 |
| | 135 |
|
| Taxes other than income | 15 |
| | 15 |
| | 43 |
| | 43 |
|
| Total operating expenses | 268 |
|
| 277 |
|
| 820 |
|
| 859 |
|
| Operating income | 51 |
|
| 51 |
|
| 167 |
|
| 142 |
|
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (15 | ) | | (15 | ) | | (45 | ) | | (42 | ) |
| Other, net | 2 |
| | 2 |
| | 10 |
| | 7 |
|
| Total other income and (deductions) | (13 | ) |
| (13 | ) |
| (35 | ) |
| (35 | ) |
| Income before income taxes | 38 |
| | 38 |
| | 132 |
| | 107 |
|
| Income taxes | 5 |
| | 5 |
| | 16 |
| | 17 |
|
| Net income | $ | 33 |
|
| $ | 33 |
|
| $ | 116 |
|
| $ | 90 |
|
| Comprehensive income | $ | 33 |
| | $ | 33 |
| | $ | 116 |
| | $ | 90 |
|
DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | |
| Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 |
| Cash flows from operating activities | | | |
| Net income | $ | 91 | | | $ | 116 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation and amortization | 143 | | | 138 | |
| | | |
| Deferred income taxes and amortization of investment tax credits | (20) | | | (2) | |
| | | |
| Other non-cash operating activities | 47 | | | 21 | |
| Changes in assets and liabilities: | | | |
| Accounts receivable | 3 | | | 29 | |
| Receivables from and payables to affiliates, net | (5) | | | (7) | |
| Inventories | (3) | | | (7) | |
| Accounts payable and accrued expenses | 21 | | | 3 | |
| | | |
| Income taxes | (12) | | | 11 | |
| Pension and non-pension postretirement benefit contributions | (1) | | | (1) | |
| Other assets and liabilities | (25) | | | (22) | |
| Net cash flows provided by operating activities | 239 | | | 279 | |
| Cash flows from investing activities | | | |
| Capital expenditures | (278) | | | (245) | |
| | | |
| | | |
| | | |
| Other investing activities | (3) | | | 1 | |
| Net cash flows used in investing activities | (281) | | | (244) | |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | (56) | | | 57 | |
| Issuance of long-term debt | 178 | | | 0 | |
| Retirement of long-term debt | (79) | | | 0 | |
| | | |
| Dividends paid on common stock | (99) | | | (105) | |
| Contributions from parent | 112 | | | 0 | |
| Other financing activities | (1) | | | 0 | |
| Net cash flows provided by (used in) financing activities | 55 | | | (48) | |
| Increase (decrease) in cash, cash equivalents, and restricted cash | 13 | | | (13) | |
| Cash, cash equivalents, and restricted cash at beginning of period | 13 | | | 24 | |
| Cash, cash equivalents, and restricted cash at end of period | $ | 26 | | | $ | 11 | |
| | | |
| Supplemental cash flow information | | | |
| Increase (decrease) in capital expenditures not paid | $ | 8 | | | $ | (13) | |
| | | |
| | | |
See the Combined Notes to Consolidated Financial Statements
48
|
| | | | | | | |
| | Nine Months Ended
September 30, |
| (In millions) | 2019 |
| 2018 |
| Cash flows from operating activities | | | |
| Net income | $ | 116 |
| | $ | 90 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation and amortization | 138 |
| | 135 |
|
| Deferred income taxes and amortization of investment tax credits | (2 | ) | | 24 |
|
| Other non-cash operating activities | 21 |
| | 16 |
|
| Changes in assets and liabilities: | | | |
| Accounts receivable | 29 |
| | 13 |
|
| Receivables from and payables to affiliates, net | (7 | ) | | (14 | ) |
| Inventories | (7 | ) | | (3 | ) |
| Accounts payable and accrued expenses | 3 |
| | 18 |
|
| Income taxes | 11 |
| | — |
|
| Pension and non-pension postretirement benefit contributions | (1 | ) | | — |
|
| Other assets and liabilities | (22 | ) | | 13 |
|
| Net cash flows provided by operating activities | 279 |
|
| 292 |
|
| Cash flows from investing activities | | | |
| Capital expenditures | (245 | ) | | (254 | ) |
| Other investing activities | 1 |
| | 1 |
|
| Net cash flows used in investing activities | (244 | ) |
| (253 | ) |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | 57 |
| | (216 | ) |
| Issuance of long-term debt | — |
| | 200 |
|
| Retirement of long-term debt | — |
| | (4 | ) |
| Dividends paid on common stock | (105 | ) | | (58 | ) |
| Contributions from parent | — |
| | 150 |
|
| Other financing activities | — |
| | (3 | ) |
| Net cash flows (used in) provided by financing activities | (48 | ) |
| 69 |
|
| (Decrease) increase in cash, cash equivalents and restricted cash | (13 | ) | | 108 |
|
| Cash, cash equivalents and restricted cash at beginning of period | 24 |
| | 2 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 11 |
|
| $ | 110 |
|
| | | | |
| Supplemental cash flow information | | | |
| (Decrease) increase in capital expenditures not paid | $ | (13 | ) | | $ | 20 |
|
DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 26 | | | $ | 13 | |
| | | |
| Accounts receivable | | | |
| Customer accounts receivable | 141 | | 152 |
| Customer allowance for credit losses | (22) | | (11) |
| Customer accounts receivable, net | 119 | | | 141 | |
| Other accounts receivable | 53 | | 42 |
| Other allowance for credit losses | (8) | | (4) |
| Other accounts receivable, net | 45 | | | 38 | |
| | | |
| | | |
| Inventories, net | | | |
| Fossil fuel | 7 | | | 8 | |
| Materials and supplies | 49 | | | 44 | |
| Prepaid utility taxes | 17 | | | 18 | |
| | | |
| Regulatory assets | 51 | | | 52 | |
| Renewable energy credits | 4 | | | 9 | |
| Other | 3 | | | 2 | |
| Total current assets | 321 | | | 325 | |
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,502 and $1,425 as of September 30, 2020 and December 31, 2019, respectively) | 4,209 | | | 4,035 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 227 | | | 222 | |
| | | |
| Goodwill | 8 | | | 8 | |
| Prepaid pension asset | 164 | | | 171 | |
| Other | 63 | | | 69 | |
| Total deferred debits and other assets | 462 | | | 470 | |
| Total assets | $ | 4,992 | | | $ | 4,830 | |
See the Combined Notes to Consolidated Financial Statements
49
|
| | | | | | | |
| (In millions) | September 30, 2019 | | December 31, 2018 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 11 |
| | $ | 23 |
|
| Restricted cash and cash equivalents | — |
| | 1 |
|
| Accounts receivable, net | | | |
| Customer (net of allowance for uncollectible accounts of $10 and $12 as of September 30, 2019 and December 31, 2018, respectively) | 112 |
| | 134 |
|
| Other (net of allowance for uncollectible accounts of $1 as of both September 30, 2019 and December 31, 2018) | 37 |
| | 46 |
|
| Inventories, net | | | |
| Fossil Fuel | 8 |
| | 9 |
|
| Materials and supplies | 47 |
| | 37 |
|
| Prepaid utility taxes | 15 |
| | 17 |
|
| Regulatory assets | 62 |
| | 59 |
|
| Other | 5 |
| | 10 |
|
| Total current assets | 297 |
|
| 336 |
|
| Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,407 and $1,329 as of September 30, 2019 and December 31, 2018, respectively) | 3,941 |
| | 3,821 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 221 |
| | 231 |
|
| Goodwill | 8 |
| | 8 |
|
| Prepaid pension asset | 175 |
| | 186 |
|
| Other | 82 |
| | 6 |
|
| Total deferred debits and other assets | 486 |
|
| 431 |
|
| Total assets | $ | 4,724 |
|
| $ | 4,588 |
|
DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 0 | | | $ | 56 | |
| Long-term debt due within one year | 81 | | | 80 | |
| Accounts payable | 126 | | | 112 | |
| Accrued expenses | 50 | | | 46 | |
| Payables to affiliates | 23 | | | 32 | |
| | | |
| Customer deposits | 34 | | | 36 | |
| Regulatory liabilities | 46 | | | 37 | |
| Other | 19 | | | 15 | |
| Total current liabilities | 379 | | | 414 | |
| Long-term debt | 1,595 | | | 1,487 | |
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 689 | | | 655 | |
| Asset retirement obligations | 14 | | | 12 | |
| | | |
| Non-pension postretirement benefits obligations | 14 | | | 16 | |
| Regulatory liabilities | 516 | | | 574 | |
| Other | 101 | | | 92 | |
| Total deferred credits and other liabilities | 1,334 | | | 1,349 | |
| Total liabilities | 3,308 | | | 3,250 | |
| Commitments and contingencies | | | |
| Shareholder's equity | | | |
| Common stock | 1,089 | | | 977 | |
| | | |
| Retained earnings | 595 | | | 603 | |
| Total shareholder's equity | 1,684 | | | 1,580 | |
| Total liabilities and shareholder's equity | $ | 4,992 | | | $ | 4,830 | |
See the Combined Notes to Consolidated Financial Statements
50
|
| | | | | | | |
| (In millions) | September 30, 2019 | | December 31, 2018 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | |
| Short-term borrowings | $ | 57 |
| | $ | — |
|
| Long-term debt due within one year | 91 |
| | 91 |
|
| Accounts payable | 90 |
| | 111 |
|
| Accrued expenses | 59 |
| | 39 |
|
| Payables to affiliates | 26 |
| | 33 |
|
| Customer deposits | 36 |
| | 35 |
|
| Regulatory liabilities | 43 |
| | 59 |
|
| Other | 33 |
| | 7 |
|
| Total current liabilities | 435 |
| | 375 |
|
| Long-term debt | 1,404 |
| | 1,403 |
|
| Deferred credits and other liabilities | | | |
| Deferred income taxes and unamortized investment tax credits | 655 |
| | 628 |
|
| Non-pension postretirement benefits obligations | 16 |
| | 17 |
|
| Regulatory liabilities | 580 |
| | 606 |
|
| Other | 114 |
| | 50 |
|
| Total deferred credits and other liabilities | 1,365 |
|
| 1,301 |
|
| Total liabilities | 3,204 |
|
| 3,079 |
|
| Commitments and contingencies |
| |
|
| Shareholder's equity | | | |
| Common stock | 914 |
| | 914 |
|
| Retained earnings | 606 |
| | 595 |
|
| Total shareholder's equity | 1,520 |
|
| 1,509 |
|
| Total liabilities and shareholder's equity | $ | 4,724 |
|
| $ | 4,588 |
|
DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| (In millions) | Common Stock | | | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2019 | $ | 977 | | | | | $ | 603 | | | $ | 1,580 | |
| Net income | — | | | | | 45 | | | 45 | |
| Common stock dividends | — | | | | | (52) | | | (52) | |
| Contributions from parent | 6 | | | | | — | | | 6 | |
| Balance, March 31, 2020 | $ | 983 | | | | | $ | 596 | | | $ | 1,579 | |
| Net income | — | | | | | 19 | | | 19 | |
| Common stock dividends | — | | | | | (14) | | | (14) | |
| Contributions from parent | 100 | | | | | — | | | 100 | |
| Balance, June 30, 2020 | $ | 1,083 | | | | | $ | 601 | | | $ | 1,684 | |
| Net income | — | | | | | 27 | | | 27 | |
| Common stock dividends | — | | | | | (33) | | | (33) | |
| Contributions from parent | 6 | | | | | — | | | 6 | |
| Balance, September 30, 2020 | $ | 1,089 | | | | | $ | 595 | | | $ | 1,684 | |
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 |
| (In millions) | Common Stock | | | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2018 | $ | 914 | | | | | $ | 595 | | | $ | 1,509 | |
| Net income | — | | | | | 53 | | | 53 | |
| Common stock dividends | — | | | | | (41) | | | (41) | |
| | | | | | | |
| Balance, March 31, 2019 | $ | 914 | | | | | $ | 607 | | | $ | 1,521 | |
| Net income | — | | | | | 30 | | | 30 | |
| Common stock dividends | — | | | | | (29) | | | (29) | |
| | | | | | | |
| Balance, June 30, 2019 | $ | 914 | | | | | $ | 608 | | | $ | 1,522 | |
| Net income | — | | | | | 33 | | | 33 | |
| Common stock dividends | — | | | | | (35) | | | (35) | |
| | | | | | | |
| Balance, September 30, 2019 | $ | 914 | | | | | $ | 606 | | | $ | 1,520 | |
See the Combined Notes to Consolidated Financial Statements
51
|
| | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2018 | $ | 914 |
| | $ | 595 |
| | $ | 1,509 |
|
| Net income | — |
| | 53 |
| | 53 |
|
| Common stock dividends | — |
| | (41 | ) | | (41 | ) |
| Balance, March 31, 2019 | $ | 914 |
| | $ | 607 |
| | $ | 1,521 |
|
| Net income | — |
| | 30 |
| | 30 |
|
| Common stock dividends | — |
| | (29 | ) | | (29 | ) |
| Balance, June 30, 2019 | $ | 914 |
| | $ | 608 |
| | $ | 1,522 |
|
| Net income | — |
| | 33 |
| | 33 |
|
| Common stock dividends | — |
| | (35 | ) | | (35 | ) |
| Balance, September 30, 2019 | $ | 914 |
| | $ | 606 |
| | $ | 1,520 |
|
|
| | | | | | | | | | | |
| | Nine Months Ended September 30, 2018 |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2017 | $ | 764 |
| | $ | 571 |
| | $ | 1,335 |
|
| Net income | — |
| | 31 |
| | 31 |
|
| Common stock dividends | — |
| | (36 | ) | | (36 | ) |
| Balance, March 31, 2018 | $ | 764 |
| | $ | 566 |
| | $ | 1,330 |
|
| Net income | — |
| | 26 |
| | 26 |
|
| Common stock dividends | — |
| | (4 | ) | | (4 | ) |
| Contributions from parent | 150 |
| | — |
| | 150 |
|
| Balance, June 30, 2018 | $ | 914 |
| | $ | 588 |
| | $ | 1,502 |
|
| Net income | — |
| | 33 |
| | 33 |
|
| Common stock dividends | — |
| | (18 | ) | | (18 | ) |
| Balance, September 30, 2018 | $ | 914 |
| | $ | 603 |
| | $ | 1,517 |
|
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 | | 2020 | | 2019 |
| Operating revenues | | | | | | | |
| Electric operating revenues | $ | 414 | | | $ | 417 | | | $ | 969 | | | $ | 964 | |
| Revenues from alternative revenue programs | 5 | | | 1 | | | (20) | | | 0 | |
| Operating revenues from affiliates | 1 | | | 1 | | | 3 | | | 2 | |
| Total operating revenues | 420 | | | 419 | | | 952 | | | 966 | |
| Operating expenses | | | | | | | |
| Purchased power | 207 | | | 207 | | | 460 | | | 463 | |
| Purchased power from affiliate | 4 | | | 3 | | | 9 | | | 16 | |
| Operating and maintenance | 45 | | | 54 | | | 140 | | | 142 | |
| Operating and maintenance from affiliates | 32 | | | 32 | | | 98 | | | 99 | |
| Depreciation and amortization | 48 | | | 43 | | | 134 | | | 114 | |
| Taxes other than income taxes | 2 | | | 1 | | | 6 | | | 4 | |
| Total operating expenses | 338 | | | 340 | | | 847 | | | 838 | |
| Gain on sale of assets | 0 | | | 0 | | | 2 | | | 0 | |
| | | | | | | |
| | | | | | | |
| Operating income | 82 | | | 79 | | | 107 | | | 128 | |
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (15) | | | (15) | | | (45) | | | (44) | |
| | | | | | | |
| Other, net | 1 | | | 1 | | | 5 | | | 5 | |
| Total other income and (deductions) | (14) | | | (14) | | | (40) | | | (39) | |
| Income before income taxes | 68 | | | 65 | | | 67 | | | 89 | |
| Income taxes | (7) | | | 2 | | | (39) | | | 2 | |
| | | | | | | |
| Net income | $ | 75 | | | $ | 63 | | | $ | 106 | | | $ | 87 | |
| Comprehensive income | $ | 75 | | | $ | 63 | | | $ | 106 | | | $ | 87 | |
See the Combined Notes to Consolidated Financial Statements
52
|
| | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| (In millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Operating revenues | | | | | | | |
| Electric operating revenues | $ | 417 |
| | $ | 406 |
| | $ | 964 |
| | $ | 983 |
|
| Revenues from alternative revenue programs | 1 |
| | (1 | ) | | — |
| | (4 | ) |
| Operating revenues from affiliates | 1 |
| | 1 |
| | 2 |
| | 2 |
|
| Total operating revenues | 419 |
| | 406 |
| | 966 |
| | 981 |
|
| Operating expenses | | | | | | | |
| Purchased power | 207 |
| | 188 |
| | 463 |
| | 465 |
|
| Purchased power from affiliates | 3 |
| | 10 |
| | 16 |
| | 21 |
|
| Operating and maintenance | 54 |
| | 52 |
| | 142 |
| | 146 |
|
| Operating and maintenance from affiliates | 32 |
| | 33 |
| | 99 |
| | 104 |
|
| Depreciation and amortization | 43 |
| | 38 |
| | 114 |
| | 107 |
|
| Taxes other than income | 1 |
| | 1 |
| | 4 |
| | 4 |
|
| Total operating expenses | 340 |
| | 322 |
| | 838 |
| | 847 |
|
| Operating income | 79 |
|
| 84 |
| | 128 |
|
| 134 |
|
| Other income and (deductions) | | | | | | | |
| Interest expense, net | (15 | ) | | (16 | ) | | (44 | ) | | (48 | ) |
| Other, net | 1 |
| | 1 |
| | 5 |
| | 2 |
|
| Total other income and (deductions) | (14 | ) | | (15 | ) | | (39 | ) | | (46 | ) |
| Income before income taxes | 65 |
| | 69 |
| | 89 |
| | 88 |
|
| Income taxes | 2 |
| | 8 |
| | 2 |
| | 12 |
|
| Net income | $ | 63 |
|
| $ | 61 |
|
| $ | 87 |
|
| $ | 76 |
|
| Comprehensive income | $ | 63 |
| | $ | 61 |
| | $ | 87 |
| | $ | 76 |
|
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | |
| Nine Months Ended
September 30, |
| (In millions) | 2020 | | 2019 |
| Cash flows from operating activities | | | |
| Net income | $ | 106 | | | $ | 87 | |
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation and amortization | 134 | | | 114 | |
| Deferred income taxes and amortization of investment tax credits | (40) | | | 2 | |
| Other non-cash operating activities | 34 | | | 21 | |
| Changes in assets and liabilities: | | | |
| Accounts receivable | (62) | | | (44) | |
| Receivables from and payables to affiliates, net | 2 | | | (4) | |
| Inventories | 0 | | | (4) | |
| Accounts payable and accrued expenses | 16 | | | 27 | |
| Income taxes | 4 | | | 5 | |
| Pension and non-pension postretirement benefit contributions | (3) | | | 0 | |
| Other assets and liabilities | (53) | | | (18) | |
| Net cash flows provided by operating activities | 138 | | | 186 | |
| Cash flows from investing activities | | | |
| Capital expenditures | (281) | | | (300) | |
| | | |
| | | |
| Other investing activities | 5 | | | 0 | |
| Net cash flows used in investing activities | (276) | | | (300) | |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | (70) | | | 49 | |
| | | |
| Repayments of short-term borrowings with maturities greater than 90 days | 0 | | | (125) | |
| Issuance of long-term debt | 123 | | | 150 | |
| Retirement of long-term debt | (38) | | | (13) | |
| Changes in PHI intercompany money pool | 117 | | | 0 | |
| Dividends paid on common stock | (111) | | | (100) | |
| Contributions from parent | 117 | | | 155 | |
| Other financing activities | (1) | | | (1) | |
| Net cash flows provided by financing activities | 137 | | | 115 | |
| (Decrease) increase in cash, cash equivalents, and restricted cash | (1) | | | 1 | |
| Cash, cash equivalents, and restricted cash at beginning of period | 28 | | | 30 | |
| Cash, cash equivalents, and restricted cash at end of period | $ | 27 | | | $ | 31 | |
| | | |
| Supplemental cash flow information | | | |
| Increase (decrease) in capital expenditures not paid | $ | 9 | | | $ | (37) | |
| | | |
| | | |
See the Combined Notes to Consolidated Financial Statements
53
|
| | | | | | | |
| | Nine Months Ended
September 30, |
| (In millions) | 2019 |
| 2018 |
| Cash flows from operating activities | | | |
| Net income | $ | 87 |
| | $ | 76 |
|
| Adjustments to reconcile net income to net cash flows provided by operating activities: | | | |
| Depreciation and amortization | 114 |
| | 107 |
|
| Deferred income taxes and amortization of investment tax credits | 2 |
| | 24 |
|
| Other non-cash operating activities | 21 |
| | 24 |
|
| Changes in assets and liabilities: | | | |
| Accounts receivable | (44 | ) | | (66 | ) |
| Receivables from and payables to affiliates, net | (4 | ) | | (3 | ) |
| Inventories | (4 | ) | | (2 | ) |
| Accounts payable and accrued expenses | 27 |
| | 21 |
|
| Income taxes | 5 |
| | (3 | ) |
| Pension and non-pension postretirement benefit contributions | — |
| | (6 | ) |
| Other assets and liabilities | (18 | ) | | (12 | ) |
| Net cash flows provided by operating activities | 186 |
| | 160 |
|
| Cash flows from investing activities | | | |
| Capital expenditures | (300 | ) | | (247 | ) |
| Other investing activities | — |
| | (1 | ) |
| Net cash flows used in investing activities | (300 | ) | | (248 | ) |
| Cash flows from financing activities | | | |
| Changes in short-term borrowings | 49 |
| | 37 |
|
| Proceeds from short-term borrowings with maturities greater than 90 days | — |
| | 125 |
|
| Repayments of short-term borrowings with maturities greater than 90 days | (125 | ) | | — |
|
| Issuance of long-term debt | 150 |
| | — |
|
| Retirement of long-term debt | (13 | ) | | (22 | ) |
| Contributions from parent | 155 |
| | — |
|
| Dividends paid on common stock | (100 | ) | | (46 | ) |
| Other financing activities | (1 | ) | | — |
|
| Net cash flows provided by financing activities | 115 |
| | 94 |
|
| Increase in cash, cash equivalents and restricted cash | 1 |
| | 6 |
|
| Cash, cash equivalents and restricted cash at beginning of period | 30 |
| | 31 |
|
| Cash, cash equivalents and restricted cash at end of period | $ | 31 |
|
| $ | 37 |
|
| | | | |
| Supplemental cash flow information | | | |
| (Decrease) increase in capital expenditures not paid | $ | (37 | ) | | $ | 16 |
|
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | |
| (In millions) | September 30, 2020 | | December 31, 2019 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 13 | | | $ | 12 | |
| Restricted cash and cash equivalents | 4 | | | 2 | |
| Accounts receivable | | | |
| Customer accounts receivable | 165 | | 121 |
| Customer allowance for credit losses | (32) | | (13) |
| Customer accounts receivable, net | 133 | | | 108 | |
| Other accounts receivable | 65 | | 53 |
| Other allowance for credit losses | (11) | | (5) |
| Other accounts receivable, net | 54 | | | 48 | |
| | | |
| Receivables from affiliates | 1 | | | 4 | |
| | | |
| Inventories, net | 34 | | | 34 | |
| | | |
| | | |
| Prepaid utility taxes | 9 | | | 0 | |
| Regulatory assets | 88 | | | 57 | |
| Other | 4 | | | 5 | |
| Total current assets | 340 | | | 270 | |
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,276 and $1,210 as of September 30, 2020 and December 31, 2019, respectively) | 3,372 | | | 3,190 | |
| Deferred debits and other assets | | | |
| Regulatory assets | 395 | | | 368 | |
| | | |
| | | |
| | | |
| Prepaid pension asset | 44 | | | 52 | |
| | | |
| Other | 50 | | | 53 | |
| Total deferred debits and other assets | 489 | | | 473 | |
Total assets(a) | $ | 4,201 | | | $ | 3,933 | |
See the Combined Notes to Consolidated Financial Statements
54
|
| | | | | | | |
| (In millions) | September 30, 2019 | | December 31, 2018 |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 13 |
| | $ | 7 |
|
| Restricted cash and cash equivalents | 3 |
| | 4 |
|
| Accounts receivable, net | | | |
| Customer (net of allowance for uncollectible accounts of $15 and $18 as of September 30, 2019 and December 31, 2018, respectively) | 142 |
| | 95 |
|
| Other (net of allowance for uncollectible accounts of $5 and $1 as of September 30, 2019 and December 31, 2018, respectively) | 47 |
| | 55 |
|
| Receivables from affiliates | 1 |
| | 1 |
|
| Inventories, net | 37 |
| | 33 |
|
| Prepaid utility taxes | 9 |
| | — |
|
| Regulatory assets | 48 |
| | 40 |
|
| Other | 7 |
| | 5 |
|
| Total current assets | 307 |
| | 240 |
|
| Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,192 and $1,137 as of September 30, 2019 and December 31, 2018, respectively) | 3,124 |
| | 2,966 |
|
| Deferred debits and other assets | | | |
| Regulatory assets | 370 |
| | 386 |
|
| Prepaid pension asset | 56 |
| | 67 |
|
| Other | 59 |
| | 40 |
|
| Total deferred debits and other assets | 485 |
| | 493 |
|
Total assets(a) | $ | 3,916 |
| | $ | 3,699 |
|
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | (In millions) | September 30, 2019 | | December 31, 2018 | (In millions) | September 30, 2020 | | December 31, 2019 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | | LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| Current liabilities | | | | Current liabilities | |
| Short-term borrowings | $ | 63 |
| | $ | 139 |
| Short-term borrowings | $ | 0 | | | $ | 70 | |
| Long-term debt due within one year | 19 |
| | 18 |
| Long-term debt due within one year | 261 | | | 20 | |
| Accounts payable | 139 |
| | 154 |
| Accounts payable | 168 | | | 144 | |
| Accrued expenses | 40 |
| | 35 |
| Accrued expenses | 42 | | | 42 | |
| Payables to affiliates | 24 |
| | 28 |
| Payables to affiliates | 24 | | | 25 | |
| | Borrowings from PHI intercompany money pool | | Borrowings from PHI intercompany money pool | 117 | | | 0 | |
| Customer deposits | 26 |
| | 26 |
| Customer deposits | 23 | | | 25 | |
| Regulatory liabilities | 25 |
| | 18 |
| Regulatory liabilities | 48 | | | 25 | |
| Other | 11 |
| | 4 |
| Other | 10 | | | 9 | |
| Total current liabilities | 347 |
| | 422 |
| Total current liabilities | 693 | | | 360 | |
| Long-term debt | 1,305 |
| | 1,170 |
| Long-term debt | 1,156 | | | 1,307 | |
| Deferred credits and other liabilities | | | | Deferred credits and other liabilities | |
| Deferred income taxes and unamortized investment tax credits | 569 |
| | 535 |
| Deferred income taxes and unamortized investment tax credits | 617 | | | 577 | |
| | Non-pension postretirement benefit obligations | 18 |
| | 17 |
| Non-pension postretirement benefit obligations | 16 | | | 17 | |
| | Regulatory liabilities | 365 |
| | 402 |
| Regulatory liabilities | 279 | | | 357 | |
| | Other | 44 |
| | 27 |
| Other | 52 | | | 39 | |
| Total deferred credits and other liabilities | 996 |
| | 981 |
| Total deferred credits and other liabilities | 964 | | | 990 | |
Total liabilities(a) | 2,648 |
| | 2,573 |
| Total liabilities(a) | 2,813 | | | 2,657 | |
| Commitments and contingencies |
| |
| Commitments and contingencies | | | |
| Shareholder's equity | | | | Shareholder's equity | |
| Common stock | 1,134 |
| | 979 |
| Common stock | 1,271 | | | 1,154 | |
| Retained earnings | 134 |
| | 147 |
| Retained earnings | 117 | | | 122 | |
| | Total shareholder's equity | 1,268 |
|
| 1,126 |
| Total shareholder's equity | 1,388 | | | 1,276 | |
| Total liabilities and shareholder's equity | $ | 3,916 |
|
| $ | 3,699 |
| Total liabilities and shareholder's equity | $ | 4,201 | | | $ | 3,933 | |
__________
| |
(a) | ACE’s consolidated total assets include $18 million and $23 million at September 30, 2019 and December 31, 2018, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $46 million and $59 million at September 30, 2019 and December 31, 2018, 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. |
(a)ACE’s consolidated total assets include $14 million and $17 million at September 30, 2020 and December 31, 2019, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $26 million and $41 million at September 30, 2020 and December 31, 2019, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 16 — Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
55
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| (In millions) | Common Stock | | | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2019 | $ | 1,154 | | | | | $ | 122 | | | $ | 1,276 | |
| Net income | — | | | | | 13 | | | 13 | |
| Common stock dividends | — | | | | | (23) | | | (23) | |
| Contributions from parent | 1 | | | | | — | | | 1 | |
| Balance, March 31, 2020 | $ | 1,155 | | | | | $ | 112 | | | $ | 1,267 | |
| Net income | — | | | | | 18 | | | 18 | |
| Common stock dividends | — | | | | | (12) | | | (12) | |
| Contributions from parent | 115 | | | | | — | | | 115 | |
| Balance, June 30, 2020 | $ | 1,270 | | | | | $ | 118 | | | $ | 1,388 | |
| Net income | — | | | | | 75 | | | 75 | |
| Common stock dividends | — | | | | | (76) | | | (76) | |
| Contributions from parent | 1 | | | | | — | | | 1 | |
| Balance, September 30, 2020 | $ | 1,271 | | | | | $ | 117 | | | $ | 1,388 | |
|
| | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2018 | $ | 979 |
| | $ | 147 |
| | $ | 1,126 |
|
| Net income | — |
| | 10 |
| | 10 |
|
| Common stock dividends | — |
| | (12 | ) | | (12 | ) |
| Contributions from parent | 5 |
| | — |
| | 5 |
|
| Balance, March 31, 2019 | $ | 984 |
| | $ | 145 |
| | $ | 1,129 |
|
| Net income | — |
| | 14 |
| | 14 |
|
| Common stock dividends | — |
| | (12 | ) | | (12 | ) |
| Contributions from parent | 150 |
| | — |
| | 150 |
|
| Balance, June 30, 2019 | $ | 1,134 |
|
| $ | 147 |
| | $ | 1,281 |
|
| Net income | — |
| | 63 |
| | 63 |
|
| Common stock dividends | — |
| | (76 | ) | | (76 | ) |
| Balance, September 30, 2019 | $ | 1,134 |
| | $ | 134 |
| | $ | 1,268 |
|
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 |
| (In millions) | Common Stock | | | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2018 | $ | 979 | | | | | $ | 147 | | | $ | 1,126 | |
| Net income | — | | | | | 10 | | | 10 | |
| Common stock dividends | — | | | | | (12) | | | (12) | |
| Contributions from parent | 5 | | | | | — | | | 5 | |
| Balance, March 31, 2019 | $ | 984 | | | | | $ | 145 | | | $ | 1,129 | |
| Net income | — | | | | | 14 | | | 14 | |
| Common stock dividends | — | | | | | (12) | | | (12) | |
| Contributions from parent | 150 | | | | | — | | | 150 | |
| Balance, June 30, 2019 | $ | 1,134 | | | | | $ | 147 | | | $ | 1,281 | |
| Net income | — | | | | | 63 | | | 63 | |
| Common stock dividends | — | | | | | (76) | | | (76) | |
| | | | | | | |
| Balance, September 30, 2019 | $ | 1,134 | | | | | $ | 134 | | | $ | 1,268 | |
|
| | | | | | | | | | | |
| | Nine Months Ended September 30, 2018 |
| (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
| Balance, December 31, 2017 | $ | 912 |
| | $ | 131 |
| | $ | 1,043 |
|
| Net income | — |
| | 7 |
| | 7 |
|
| Common stock dividends | — |
| | (9 | ) | | (9 | ) |
| Balance, March 31, 2018 | $ | 912 |
| | $ | 129 |
| | $ | 1,041 |
|
| Net income | — |
| | 8 |
| | 8 |
|
| Common stock dividends | — |
| | (10 | ) | | (10 | ) |
| Balance, June 30, 2018 | $ | 912 |
|
| $ | 127 |
| | $ | 1,039 |
|
| Net income | — |
| | 61 |
| | 61 |
|
| Common stock dividends | — |
| | (27 | ) | | (27 | ) |
| Balance, September 30, 2018 | $ | 912 |
| | $ | 161 |
| | $ | 1,073 |
|
See the Combined Notes to Consolidated Financial Statements
56
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 1 — Significant Accounting Policies
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.
|
| | | | | | | | | | | | | |
| 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. | | Five reportable segments: Mid-Atlantic, Midwest, 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)
Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
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.
The accompanying consolidated financial statements as of September 30, 20192020 and 2018December 31, 2019 and for the three and nine months then ended September 30, 2020 and 2019 are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 20182019 Consolidated Balance Sheets were derived from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 1 — Significant Accounting Policies
the fiscal year ending December 31, 2019. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.
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, our allowance for credit losses and the carrying value of our goodwill and other long-lived assets, in context with the information reasonably available to us and the unknown future impacts of COVID-19 as of September 30, 2020 and through the date of this report. The Registrants' future assessment of our 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.
New Accounting Standards (All Registrants)
New Accounting Standards Adopted in 2019: In 2019, the Registrants have adopted the following new authoritative accounting guidance issued by the FASB.
Leases. The Registrants applied the new guidance with the following transition practical expedients:
a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carry forward 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 standard materially impacted the Registrants' Consolidated Balance Sheets but did not have a material impact in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders' Equity. The most significant impact was the recognition of the ROU assets and lease liabilities for operating leases. The operating ROU assets and lease liabilities recognized upon adoption are materially consistent with the balances presented in the Combined Notes to the Consolidated Financial Statements. See Note 5 - Leases for additional information.
See Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K for additional information on new accounting standards issued and adopted as of January 1, 2019.
New Accounting Standards Issued and Not Yet Adopted as of September 30, 2019:2020: The following new authoritative accounting guidance issued by the FASB has not yet beenwas adopted as of January 1, 2020 and was reflected by the Registrants in their consolidated financial statements beginning in the first quarter of 2020.
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 its current estimate of credit losses expected to be incurred over the life of the financial instrument based on historical experience, current conditions and reasonable and supportable forecasts. The standard was effective January 1, 2020 and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of September 30, 2019. Unless otherwise indicated, the Registrants are currently assessingbeginning of the impacts suchperiod of adoption. This standard was primarily applicable to Generation's and the Utility Registrants' Customer accounts receivables balances. This guidance may have (which could be material) in their financial statements. The Registrants have assessed other FASB issuances of new standards which aredid not listed below as the Registrants do not expect such standards to have a materialsignificant impact to theiron the Registrants’ consolidated financial statements.
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. The standard was effective January 1, 2020 and must be applied on a prospective basis. Exelon, Generation, ComEd, PHI, and DPL will apply the new guidance for their goodwill impairment assessments in 2020 and do not expect the updated guidance to have a material impact to their financial statements. 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). ProvidesAllowance for a new Current Expected Credit Loss (CECL) impairment modelLosses on Accounts Receivables (All Registrants)
The allowance 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 its current estimate of credit losses expected to be incurred overreflects the lifeRegistrants’ best estimates of losses on the financial instrumentcustomers' accounts receivable balances based on historical experience, current conditionsinformation, and reasonable and supportable forecasts. The standard will be 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 receivable balances. The Registrants do not expect that this guidance will have a significant impact on their consolidated financial statements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Note 1 — Significant Accounting Policies
Leases (All Registrants)
The allowance for credit losses for the Utility Registrants’ customers is developed by applying loss rates for each Utility 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 and Regulatory assets on ComEd, BGE, Pepco, DPL, and ACE’s Consolidated Balance Sheets. See Note 3 - Regulatory Matters of the 2019 Form 10-K for additional information regarding the regulatory recovery of credit losses on customer accounts receivable at ComEd, BGE, Pepco, DPL, and ACE.
The Registrants recognize a ROU asset and lease liability for operating leases with a term of greater than one year. The ROU asset is includedhave certain non-customer receivables in Other deferred debits and other assets and the lease liability is included in Other current liabilities and Other deferred creditswhich primarily are with governmental agencies and other liabilities onhigh-quality counterparties with no history of default. As such, the Consolidated Balance Sheets. The ROU assetallowance for credit losses related to these receivables 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.not material. The Registrants include non-lease components, whichmonitor these balances and will record an allowance if there 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.
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 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 will generally 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 5 —Leases for additional information.
2. Variable Interest Entities (Exelon, Generation, PHI and ACE)
At September 30, 2019 and December 31, 2018, 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.
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 September 30, 2019 and December 31, 2018. 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 footnote to the table below, are such that creditors, or beneficiaries, do not have recourse to the general credit of Exelon, Generation, PHI and ACE.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Variable Interest Entities
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2019 | | December 31, 2018 |
| | Exelon |
| Generation |
| PHI (a) | | ACE | | Exelon | | Generation | | PHI (a) | | ACE |
| Cash and cash equivalents | $ | 168 |
| | $ | 168 |
| | $ | — |
| | $ | — |
| | $ | 414 |
| | $ | 414 |
| | $ | — |
| | $ | — |
|
| Restricted cash and cash equivalents | 76 |
| | 73 |
| | 3 |
| | 3 |
| | 66 |
| | 62 |
| | 4 |
| | 4 |
|
| Accounts receivable, net | | | | | | | | | | | | | | | |
| Customer | 163 |
| | 163 |
| | — |
| | — |
| | 146 |
| | 146 |
| | — |
| | — |
|
| Other | 43 |
| | 43 |
| | — |
| | — |
| | 23 |
| | 23 |
| | — |
| | — |
|
Unamortized energy contract asset (b) | 23 |
| | 23 |
| | — |
| | — |
| | 25 |
| | 25 |
| | — |
| | — |
|
| Inventory, net | | | | | | | | | | | | | | | |
| Materials and supplies | 222 |
| | 222 |
| | — |
| | — |
| | 212 |
| | 212 |
| | — |
| | — |
|
| Other current assets | 50 |
| | 48 |
| | 2 |
| | — |
| | 52 |
| | 49 |
| | 3 |
| | — |
|
| Total current assets | 745 |
|
| 740 |
|
| 5 |
| | 3 |
| | 938 |
|
| 931 |
|
| 7 |
| | 4 |
|
Property, plant and equipment, net (c) | 6,079 |
| | 6,079 |
| | — |
| | — |
| | 6,188 |
| | 6,188 |
| | — |
| | — |
|
| NDT funds | 2,636 |
| | 2,636 |
| | — |
| | — |
| | 2,351 |
| | 2,351 |
| | — |
| | — |
|
Unamortized energy contract asset (b) | 258 |
| | 258 |
| | — |
| | — |
| | 274 |
| | 274 |
| | — |
| | — |
|
| Other noncurrent assets | 69 |
| | 52 |
| | 17 |
| | 15 |
| | 258 |
| | 232 |
| | 26 |
| | 19 |
|
| Total noncurrent assets | 9,042 |
|
| 9,025 |
|
| 17 |
| | 15 |
| | 9,071 |
|
| 9,045 |
|
| 26 |
| | 19 |
|
| Total assets | $ | 9,787 |
|
| $ | 9,765 |
|
| $ | 22 |
| | $ | 18 |
| | $ | 10,009 |
|
| $ | 9,976 |
|
| $ | 33 |
| | $ | 23 |
|
| Long-term debt due within one year | $ | 556 |
| | $ | 535 |
| | $ | 21 |
| | $ | 19 |
| | $ | 87 |
| | $ | 66 |
| | $ | 21 |
| | $ | 18 |
|
| Accounts payable | 148 |
| | 148 |
| | — |
| | — |
| | 96 |
| | 96 |
| | — |
| | — |
|
| Accrued expenses | 58 |
| | 57 |
| | 1 |
| | 1 |
| | 73 |
| | 72 |
| | 1 |
| | 1 |
|
| Unamortized energy contract liabilities | 10 |
| | 10 |
| | — |
| | — |
| | 15 |
| | 15 |
| | — |
| | — |
|
| Other current liabilities | 30 |
| | 30 |
| | — |
| | — |
| | 3 |
| | 3 |
| | — |
| | — |
|
| Total current liabilities | 802 |
| | 780 |
| | 22 |
| | 20 |
| | 274 |
| | 252 |
| | 22 |
| | 19 |
|
| Long-term debt | 532 |
| | 504 |
| | 28 |
| | 26 |
| | 1,072 |
| | 1,025 |
| | 47 |
| | 40 |
|
Asset retirement obligations (d) | 2,103 |
| | 2,103 |
| | — |
| | — |
| | 2,165 |
| | 2,165 |
| | — |
| | — |
|
| Unamortized energy contract liabilities | 1 |
| | 1 |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | — |
|
| Other noncurrent liabilities | 84 |
| | 84 |
| | — |
| | — |
| | 42 |
| | 42 |
| | — |
| | — |
|
| Total noncurrent liabilities | 2,720 |
| | 2,692 |
| | 28 |
| | 26 |
| | 3,280 |
| | 3,233 |
| | 47 |
| | 40 |
|
| Total liabilities | $ | 3,522 |
| | $ | 3,472 |
| | $ | 50 |
| | $ | 46 |
| | $ | 3,554 |
| | $ | 3,485 |
| | $ | 69 |
| | $ | 59 |
|
_________
| |
(a) | Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity. |
| |
(b) | These are unrestricted assets to Exelon and Generation. |
| |
(c) | Exelon’s and Generation’s balances include unrestricted assets of $41 million and $43 million as of September 30, 2019 and December 31, 2018, respectively. |
| |
(d) | Exelon’s and Generation’s balances include liabilities with recourse of $5 million as of September 30, 2019 and December 31, 2018. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Variable Interest Entities
As of September 30, 2019 and December 31, 2018, 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 Nuclear Operating Services Agreement (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. See Note 7— 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. |
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.
Exelon and Generation, where indicated, provide the following support to CENG:
Generation provided a $400 million loan to CENG. The loan balance was fully repaid 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 — Commitments and Contingencies of the Exelon 2018 Form 10-K for additional information.
|
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.
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 formindicators of a parental guarantee of debt, loans from the customersdecline 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.credit quality.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Variable Interest 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 11— Debt and Credit Agreements for additional information.
As of September 30, 2019 and December 31, 2018, 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 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. | ACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ACETF. 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 September 30, 2019 and December 31, 2018, 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.
The following table presents summary information about Exelon's and Generation’s unconsolidated VIE entities:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2019 | | December 31, 2018 |
| | Commercial Agreement VIEs | | Equity Investment VIEs | | Total | | Commercial Agreement VIEs | | Equity Investment VIEs | | Total |
Total assets(a) | $ | 614 |
| | $ | 453 |
| | $ | 1,067 |
| | $ | 597 |
| | $ | 472 |
| | $ | 1,069 |
|
Total liabilities(a) | 36 |
| | 224 |
| | 260 |
| | 37 |
| | 222 |
| | 259 |
|
Exelon's ownership interest in VIE(a) | — |
| | 201 |
| | 201 |
| | — |
| | 223 |
| | 223 |
|
Other ownership interests in VIE(a) | 587 |
| | 28 |
| | 615 |
| | 560 |
| | 27 |
| | 587 |
|
| Registrants’ maximum exposure to loss: | | | | |
| | | | | |
|
|
| Carrying amount of equity method investments | — |
| | 12 |
| | 12 |
| | — |
| | 223 |
| | 223 |
|
_________
| |
(a) | These items represent amounts in 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. |
For each of the unconsolidated VIEs, Exelon and Generation have assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Variable Interest Entities
As of September 30, 2019 and December 31, 2018, 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 these investments in the third quarter of 2019. See Note 7— 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. |
3. Mergers, Acquisitions and Dispositions (Exelon and Generation)
Acquisition of Handley Generating Station
On November 7, 2017, ExGen Texas Power, LLC (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, which resulted in Exelon and Generation deconsolidating EGTP's assets and liabilities from their consolidated financial statements. 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, which closed on April 4, 2018 for a purchase price of $62 million.
Disposition of Oyster Creek
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 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 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 recognized a loss on the sale in the third quarter, which was immaterial.
Under the terms of the transaction, Generation transferred 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. 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 the third quarter of 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. Exelon and Generation had $897 million and $777 million of Assets and Liabilities held for sale, respectively, at December 31, 2018. Upon remeasurement of the Oyster Creek ARO, Exelon and Generation recognized an $84 million and a $9 million pre-tax charge to Operating and maintenance expense in the third quarter of 2018 and in the second quarter of 2019, respectively. See Note 13 — Nuclear Decommissioning for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Mergers, Acquisitions and Dispositions
Other Asset Disposition
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 nine months ended September 30, 2018.
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.
See Note 3 — Revenue from Contracts with Customers of the Exelon 2018 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.
Contract Balances (All Registrants)
Contract Assets and Liabilities
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 Accounts receivable, net - Customer, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets.
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. 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 assets and liabilities reflected in Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to September 30, 2019:
|
| | | | | | | | | | | | | | | | |
| | | Contract Assets | | Contract Liabilities |
| | | Exelon | | Generation | | Exelon | | Generation |
| Balance as of January 1, 2018 | | $ | 283 |
| | $ | 283 |
| | $ | 35 |
| | $ | 35 |
|
| Consideration received or due | | (146 | ) | | (146 | ) | | 179 |
| | 465 |
|
| Revenues recognized | | 50 |
| | 50 |
| | (187 | ) | | (458 | ) |
| Balance at December 31, 2018 | | 187 |
| | 187 |
| | 27 |
| | 42 |
|
| Consideration received or due | | (109 | ) | | (109 | ) | | 65 |
| | 198 |
|
| Revenues recognized | | 92 |
| | 92 |
| | (66 | ) | | (192 | ) |
| Balance at September 30, 2019 | | 170 |
| | 170 |
| | 26 |
| | 48 |
|
The Utility Registrants do not have any contract assets. The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of September 30, 2019 and December 31, 2018, the Utility Registrants' contract liabilities were immaterial.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
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 September 30, 2019. 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.
|
| | | | | | | | | | | | | | | | | |
| | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and thereafter | | Total |
| Exelon | 156 |
| | 341 |
| | 142 |
| | 74 |
| | 244 |
| | 957 |
|
| Generation | 215 |
| | 442 |
| | 197 |
| | 89 |
| | 244 |
| | 1,187 |
|
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 18 — Segment Information for the presentation of the Registrant's revenue disaggregation.
5. Leases (All Registrants)
Lessee
The Registrants have operating leases for which they are the lessees. The following tables outline the significant types of operating leases at each registrant and other terms and conditions of the lease agreements. The Registrants do not have material finance leases.
|
| | | | | | | | | | | | | | | | | |
| 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 | 1-87 | | 1-37 | | 1-6 | | 1-15 | | 1-87 | | 1-13 | | 1-13 | | 1-13 | | 1-8 |
| Options to extend the term | 3-30 | | 3-30 | | 5 | | N/A | | N/A | | 3-30 | | 5 | | 3-30 | | N/A |
| Options to terminate within | 2-14 | | 2 | | 4 | | N/A | | 3 | | N/A | | N/A | | N/A | | N/A |
The components of lease costs for the three months ended September 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Operating lease costs | $ | 97 |
| | $ | 73 |
| | $ | 1 |
| | $ | — |
| | $ | 8 |
| | $ | 12 |
| | $ | 3 |
| | $ | 3 |
| | $ | 2 |
|
| Variable lease costs | 79 |
| | 74 |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | — |
| | — |
|
| Short-term lease costs | 5 |
| | 5 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total lease costs (a) | $ | 181 |
| | $ | 152 |
| | $ | 1 |
| | $ | — |
| | $ | 9 |
| | $ | 13 |
| | $ | 3 |
| | $ | 3 |
| | $ | 2 |
|
__________
| |
(a) | Excludes $29 million, $28 million, $1 million and $1 million of sublease income recorded at Exelon, Generation, PHI and DPL, respectively |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Leases
The components of lease costs for the nine months ended September 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Operating lease costs | $ | 252 |
| | $ | 180 |
| | $ | 2 |
| | $ | 1 |
| | $ | 25 |
| | $ | 35 |
| | $ | 9 |
| | $ | 10 |
| | $ | 5 |
|
| Variable lease costs | 229 |
| | 214 |
| | 1 |
| | — |
| | 1 |
| | 5 |
| | 2 |
| | 2 |
| | 1 |
|
| Short-term lease costs | 16 |
| | 16 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total lease costs (a) | $ | 497 |
| | $ | 410 |
| | $ | 3 |
| | $ | 1 |
| | $ | 26 |
| | $ | 40 |
| | $ | 11 |
| | $ | 12 |
| | $ | 6 |
|
__________ | |
(a) | Excludes $48 million, $42 million, $6 million and $6 million of sublease income recorded at Exelon, Generation, PHI and DPL, respectively. |
The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance Sheets as of September 30, 2019: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon(a) | | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Operating lease ROU assets | | | | | | | | | | | | | | | | | |
| Other deferred debits and other assets | $ | 1,374 |
| | $ | 926 |
| | $ | 10 |
| | $ | 2 |
| | $ | 83 |
| | $ | 304 |
| | $ | 66 |
| | $ | 75 |
| | $ | 24 |
|
| | | | | | | | | | | | | | | | | | |
| Operating lease liabilities | | | | | | | | | | | | | | | | | |
| Other current liabilities | 242 |
| | 170 |
| | 3 |
| | — |
| | 32 |
| | 35 |
| | 8 |
| | 11 |
| | 5 |
|
| Other deferred credits and other liabilities | 1,355 |
| | 949 |
| | 8 |
| | 1 |
| | 50 |
| | 279 |
| | 60 |
| | 74 |
| | 19 |
|
| Total operating lease liabilities | $ | 1,597 |
| | $ | 1,119 |
| | $ | 11 |
| | $ | 1 |
| | $ | 82 |
| | $ | 314 |
| | $ | 68 |
| | $ | 85 |
| | $ | 24 |
|
__________ | |
(a) | Exelon's and Generation's operating ROU assets and lease liabilities include $542 million and $703 million, respectively, related to contracted generation. |
The weighted average remaining lease terms, in years, and discount rates for operating leases as of September 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Remaining lease term | 10.1 |
| | 10.6 |
| | 4.7 |
| | 4.3 |
| | 5.6 |
| | 9.0 |
| | 9.6 |
| | 9.5 |
| | 5.3 |
|
| Discount rate | 4.5 | % | | 4.8 | % | | 3.1 | % | | 3.3 | % | | 3.6 | % | | 4.0 | % | | 3.7 | % | | 3.7 | % | | 3.3 | % |
Future minimum lease payments for operating leases as of September 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2019 | $ | 65 |
| | $ | 50 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | 11 |
| | $ | 3 |
| | $ | 2 |
| | $ | 2 |
|
| 2020 | 289 |
| | 203 |
| | 3 |
| | 1 |
| | 34 |
| | 45 |
| | 10 |
| | 13 |
| | 5 |
|
| 2021 | 246 |
| | 162 |
| | 3 |
| | — |
| | 31 |
| | 43 |
| | 9 |
| | 12 |
| | 5 |
|
| 2022 | 179 |
| | 113 |
| | 2 |
| | — |
| | 16 |
| | 42 |
| | 9 |
| | 12 |
| | 4 |
|
| 2023 | 148 |
| | 100 |
| | 1 |
| | — |
| | — |
| | 41 |
| | 8 |
| | 11 |
| | 4 |
|
| Remaining years | 1,123 |
| | 837 |
| | 2 |
| | — |
| | 19 |
| | 197 |
| | 43 |
| | 53 |
| | 6 |
|
| Total | 2,050 |
| | 1,465 |
| | 12 |
| | 1 |
| | 101 |
| | 379 |
| | 82 |
| | 103 |
| | 26 |
|
| Interest | 453 |
| | 346 |
| | 1 |
| | — |
| | 19 |
| | 65 |
| | 14 |
| | 18 |
| | 2 |
|
| Total operating lease liabilities | $ | 1,597 |
| | $ | 1,119 |
| | $ | 11 |
| | $ | 1 |
| | $ | 82 |
| | $ | 314 |
| | $ | 68 |
| | $ | 85 |
| | $ | 24 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Leases
Future minimum lease payments for operating leases under the prior lease accounting guidance as of December 31, 2018 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | 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. |
| |
(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. |
Cash paid for amounts included in the measurement of lease liabilities for the nine months ended September 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Operating cash flows from operating leases | $ | 225 |
| | $ | 156 |
| | $ | 2 |
| | $ | — |
| | $ | 32 |
| | $ | 29 |
| | $ | 7 |
| | $ | 6 |
| | $ | 4 |
|
ROU assets obtained in exchange for lease obligations for the nine months ended September 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Operating leases | $ | 70 |
| | $ | 11 |
| | $ | 6 |
| | $ | — |
| | $ | 1 |
| | $ | 20 |
| | $ | 7 |
| | $ | 9 |
| | $ | 4 |
|
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. |
| | | | | | | | | | | | | | | | | |
| 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 | 1-84 | | 1-33 | | 1-18 | | 1-84 | | 24 | | 1-14 | | 2-7 | | 13-14 | | 1-3 |
Options to extend the term | 1-79 | | 1-5 | | 5-79 | | 5-50 | | N/A | | 5 | | N/A | | N/A | | N/A |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Leases
The components of lease income for the three months ended September 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Operating lease income | $ | 30 |
| | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
|
| Variable lease income | 80 |
| | 80 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
The components of lease income for the nine months ended September 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Operating lease income | $ | 48 |
| | $ | 44 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 3 |
| | $ | — |
|
| Variable lease income | 209 |
| | 206 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | 3 |
| | — |
|
Future minimum lease payments to be recovered under operating leases as of September 30, 2019 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| 2019 | $ | 4 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
|
| 2020 | 51 |
| | 46 |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 3 |
| | — |
|
| 2021 | 50 |
| | 45 |
| | — |
| | — |
| | — |
| | 4 |
| | 1 |
| | 3 |
| | — |
|
| 2022 | 50 |
| | 45 |
| | — |
| | — |
| | — |
| | 5 |
| | — |
| | 4 |
| | — |
|
| 2023 | 49 |
| | 45 |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 3 |
| | — |
|
| Remaining years | 314 |
| | 271 |
| | 1 |
| | 3 |
| | 1 |
| | 38 |
| | — |
| | 38 |
| | — |
|
| Total | $ | 518 |
| | $ | 455 |
| | $ | 1 |
| | $ | 3 |
| | $ | 1 |
| | $ | 56 |
| | $ | 1 |
| | $ | 52 |
| | $ | — |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Regulatory Matters
6.2. Regulatory Matters (All Registrants)
As discussed in Note 43 — Regulatory Matters of the Exelon 20182019 Form 10-K, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The following discusses developments in 20192020 and updates to the 20182019 Form 10-K.
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 2019.2020.
Completed Distribution Base Rate Case Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement (Decrease) Increase | | Approved Revenue Requirement (Decrease) Increase | | Approved ROE | | Approval Date | Rate Effective Date |
ComEd - Illinois (Electric)(a) | April 8, 2019 | $ | (6) | | | $ | (17) | | | 8.91 | % | | December 4, 2019 | January 1, 2020 |
| DPL - Maryland (Electric) | December 5, 2019 (amended April 23, 2020) | 17 | | | 12 | | | 9.60 | % | | July 14, 2020 | July 16, 2020 |
| | | | | | | | | |
|
| | | | | | | | | | | | | |
| Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement (Decrease) Increase | | Approved Revenue Requirement (Decrease) Increase | | Approved ROE | | Approval Date | Rate Effective Date |
| ComEd - Illinois (Electric) | April 16, 2018 | $ | (23 | ) | | $ | (24 | ) | | 8.69% |
| December 4, 2018 | January 1, 2019 |
| PECO - Pennsylvania (Electric) | March 29, 2018 | $ | 82 |
| | $ | 25 |
| | N/A | (a) | December 20, 2018 | January 1, 2019 |
| BGE - Maryland (Natural Gas) | June 8, 2018 (amended October 12, 2018) | $ | 61 |
| | $ | 43 |
| | 9.8% | | January 4, 2019 | January 4, 2019 |
| ACE - New Jersey (Electric) | August 21, 2018 (amended November 19, 2018) | $ | 122 |
| (b) | $ | 70 |
| (b) | 9.6% | | March 13, 2019 | April 1, 2019 |
| Pepco - Maryland (Electric) | January 15, 2019 (amended May 16, 2019) | $ | 27 |
| | $ | 10 |
| | 9.6% | | August 12, 2019 | August 13, 2019 |
__________(a)Reflects an increase of $51 million for the initial revenue requirement for 2019 and a decrease of $68 million related to the annual reconciliation for 2018. The revenue requirement for 2019 and annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.51%, inclusive of an allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points.
| |
(a) | The PECO rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE. |
| |
(b) | Requested and approved increases are before New Jersey sales and use tax. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 62 — Regulatory Matters
| | | | | | | | | | | | | | |
| Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement (Decrease) Increase | Requested ROE | Expected Approval Timing |
ComEd - Illinois (Electric)(a) | April 16, 2020 | $ | (11) | | 8.38 | % | Fourth quarter of 2020 |
| PECO - Pennsylvania (Natural Gas) | September 30, 2020 | 69 | | 10.95 | % | Second quarter of 2021 |
BGE - Maryland (Electric and Natural Gas)(b) | May 15, 2020
(amended September 11, 2020) | 228 | | 10.1 | % | Fourth quarter of 2020 |
Pepco - District of Columbia (Electric)(c) | May 30, 2019 (amended June 1, 2020) | 136 | | 9.7 | % | First quarter of 2021 |
Pepco - Maryland (Electric)(d) | October 26, 2020 | 110 | | 10.2 | % | Second quarter of 2021 |
DPL - Delaware (Natural Gas)(e) | February 21, 2020 (amended October 9, 2020) | 7 | | 10.3 | % | First quarter of 2021 |
DPL - Delaware (Electric)(f) | March 6, 2020 (amended October 26, 2020) | 24 | | 10.3 | % | Second quarter of 2021 |
Pending Distribution Base Rate Case Proceedings__________
|
| | | | | | | |
| Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement (Decrease) Increase | Requested ROE | Expected Approval Timing |
ComEd - Illinois (Electric)(a) | April 8, 2019 | $ | (6 | ) | 8.91 | % | December 2019 |
BGE - Maryland (Electric)(b) | May 24, 2019 (amended October 4, 2019) | $ | 74 |
| 10.3 | % | December 2019 |
BGE - Maryland (Natural Gas)(b) | May 24, 2019 (amended October 4, 2019) | $ | 59 |
| 10.3 | % | December 2019 |
Pepco - District of Columbia (Electric)(c) | May 30, 2019 (amended September 16, 2019) | $ | 160 |
| 10.3 | % | Fourth quarter of 2020 |
__________(a)Reflects an increase of $51 million for the initial revenue requirement for 2020 and a decrease of $62 million related to the annual reconciliation for 2019. The revenue requirement for 2020 and annual reconciliation for 2019 provides 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 average rate on 30-year treasury notes plus 580 basis points. | |
(a) | Reflects an increase of $57 million for the initial revenue requirement for 2019 and a decrease of $63 million related to the annual reconciliation for 2018. The revenue requirement for 2019 and annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.53%. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information on ComEd's distribution formula rate filings. |
| |
(b) | On October 25, 2019, BGE filed a settlement agreement with the MDPSC. The settlement provides for an increase to BGE’s annual electric and natural gas distribution rates of $18 million and $45 million, respectively.Reflects a three-year cumulative multi-year plan for 2021 through 2023 and total requested revenue requirement increases in 2023 of $137 million related to electric distribution and $91 million related to natural gas distribution to recover capital investments made in late 2019 and planned capital investments from 2020 to 2023.
(c)Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects a three-year cumulative multi-year plan for 2020 through 2022 and requested revenue requirement increases of $73 million in 2022 and $63 million in 2023, to recover capital investments made during 2018 through 2020 and planned capital investments through the end of 2022. (d)Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 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. (e)The rates went into effect on September 21, 2020, subject to refund. (f)The rates went into effect on October 6, 2020, subject to refund. |
| |
(c) | Reflects a three-year cumulative multi-year plan and total requested revenue requirement increases of $84 million, $40 million and $36 million for years 2020, 2021, and 2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022. |
Transmission Formula Rates
Transmission Formula Rate (Exelon ComEd, BGE, PHI, Pepco, DPL and ACE)the Utility Registrants). ComEd’s, PECO'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-approved formula on or before May 15 and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual formula rate 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 revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation).
For 2019, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:60
|
| | | | | | | | | | | | | | |
Registrant(a) | Initial Revenue Requirement Increase (Decrease) | Annual Reconciliation (Decrease) Increase | Total Revenue Requirement Increase (Decrease) | | Allowed Return on Rate Base(c) | Allowed ROE(d) |
| ComEd | $ | 21 |
| $ | (16 | ) | $ | 5 |
| | 8.21 | % | 11.50 | % |
| BGE | (10 | ) | (23 | ) | (19 | ) | (b) | 7.35 | % | 10.50 | % |
| Pepco | 15 |
| 11 |
| 26 |
|
| 7.75 | % | 10.50 | % |
| DPL | 17 |
| (1 | ) | 16 |
|
| 7.14 | % | 10.50 | % |
| ACE | 11 |
| (2 | ) | 9 |
|
| 7.79 | % | 10.50 | % |
__________
| |
(a) | All rates are effective June 2019, subject to review by the FERC and other parties, which is due by the fourth quarter of 2019.
|
| |
(b) | The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $14 million to recover the costs of providing transmission service to specifically designated load by BGE. |
| |
(c) | Represents the weighted average debt and equity return on transmission rate bases. |
| |
(d) | 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 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 62 — Regulatory Matters
For 2020, the following total increases/(decreases) were included in ComEd’s, PECO's, BGE’s, Pepco's, DPL's, and ACE's electric transmission formula rate filings:
| | | | | | | | | | | | | | | | | | | | |
Registrant(a) | Initial Revenue Requirement Increase (Decrease) | Annual Reconciliation Decrease | Total Revenue Requirement Increase (Decrease)(c) | | Allowed Return on Rate Base(d) | Allowed ROE(e) |
| ComEd | $ | 18 | | $ | (4) | | $ | 14 | | | 8.17 | % | 11.50 | % |
PECO(b) | 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 2020, subject to review by interested parties, which is anticipated to be completed by the fourth quarter of 2020 or first quarter of 2021 for ComEd, BGE, Pepco, DPL, and ACE and second quarter of 2021 for PECO.
(b)PECO posted a revised filing to the PJM website on July 17, 2020 reflecting updates to the formula rate based on the FERC order dated July 9, 2020.
(c)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 ACE’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.
(d)Represents the weighted average debt and equity return on transmission rate bases.
(e)As part of the FERC-approved settlements of ComEd’s 2007 and PECO's 2017 transmission rate cases, the rate of return on common equity is 11.50% and 10.35%, respectively, 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%. and 55.75%, respectively. 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 (Exelon and PECO). 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. PECO’s initial formula rate filing included a requested increase of $22 million to PECO’s annual transmission revenue requirement, which reflected a ROE of 11%, inclusive of a 50 basis point adder for being a member of a RTO. 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.
Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were effective on June 1, 2018 and 2019, respectively, subject to refund.
On July 22, 2019, PECO and other parties filed with FERC a settlement agreement, which includes a ROE of 10.35%, inclusive of a 50 basis point adder for being a member of a RTO. The settlement did not have a material impact on PECO’s 2017, 2018, or 2019 annual transmission revenue requirements. A final order from FERC is expected before the end of the first quarter of 2020. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.
Other State Regulatory Matters
Illinois Regulatory Matters
Energy Efficiency Formula Rate.Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the ICC on May 23, 2019.21, 2020. The filing establishes the revenue requirement used to set the rates that will take effect in January 20202021 after the ICC’s review and approval. The revenue requirement requested is based on a reconciliation of the 20182019 actual costs plus projected 20192020 and 20202021 expenditures.
|
| | | | | | | | | | | | | | |
| Registrant | Initial Revenue Requirement Increase (Decrease) | Annual Reconciliation Increase (Decrease) | Total Revenue Requirement Increase (Decrease) | | Requested Return on Rate Base | Requested ROE |
| ComEd | $ | 53 |
| $ | (2 | ) | $ | 51 |
| (a) | 6.53 | % | 8.91 | % |
| | | | | | | | | | | | | | | | | | |
| Initial Revenue Requirement Increase | Annual Reconciliation Increase | Total Revenue Requirement Increase | | Requested Return on Rate Base | Requested ROE |
| $ | 45 | | $ | 3 | | $ | 48 | | (a) | 6.28 | % | 8.38 | % |
__________
| |
(a) | The requested revenue requirement increase provides for a weighted average debt and equity return on rate base of 6.53% inclusive of an allowed ROE of 8.91%(a)The requested revenue requirement increase provides for a weighted average debt and equity return on rate base of 6.28% inclusive of an allowed ROE of 8.38%. The ROE reflects the average rate on 30-year treasury notes plus 580 basis points. The ROE applicable to the 2018 reconciliation year is 10.91% and the return on rate base is 7.49%, which include the Performance Adjustment, which can either increase or decrease the ROE by up to a maximum of 200 basis points. |
Maryland Regulatory Matters
Maryland Alternative Rate Plans Rulemaking (Exelon, BGE, PHI, Pepco and DPL). On August 9, 2019, the MDPSC issued an order in which the MDPSC determined that it is now appropriate to move forward to implement alternative rate plans in Maryland. The MDPSC found that a multi-year rate plan, based on a historic test year and allowing up to three future test years, can produce just and reasonable rates. A working group has been convened to develop and submit a detailed implementation report to the MDPSC by December 20, 2019. The MDPSC will issue another order2019 reconciliation year is 8.96% and the return on next steps by January 30, 2020. BGE, Pepco and DPL cannot predictrate base is 6.56%, which includes a performance adjustment that can either increase or decrease the outcome or the potential financial impact, if any, on BGE, Pepco or DPL.ROE.
New Jersey Regulatory Matters61
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) 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 allowed 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 62 — Regulatory Matters
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.
New Jersey Clean Energy LegislationRegulatory Matters
Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On May 23, 2018, New Jersey enacted legislation that established and modifiedAugust 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 clean energyEnergy Master Plan and energy efficiency programsClean 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 solardata management systems. ACE is seeking authority to recover these estimated investments through a combination of the ACE Infrastructure Investment Program rider mechanism and renewable energy portfolio standards. Onfuture distribution base rates. ACE currently expects a decision in this matter in the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate tothird quarter of 2021 but cannot predict if the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality inwill approve 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 ZECs effective April 18, 2019. See Generation Regulatory Matters below for additional information.application as filed.
Other Federal Regulatory Matters
Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE). 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 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 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. As a resultIn the fourth quarter of the FERC’s order,2017, ComEd, BGE, Pepco, DPL, and ACE took a charge to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017 reducingfully impaired their associated transmission-related income tax regulatory assetsasset for the portion of the total transmission-related income tax regulatory assetsasset that would have been previously amortized and recovered through rates. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula. See above for additional information regarding PECO's transmission formula rate filing.amortized.
On December 18, 2017, BGE filed for clarification and rehearing of FERC’s November 16, 2017 order and 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 transmission formula rate provided for such recovery.
On September 7, 2018, FERC issued orders rejecting BGE’s December 18,1) BGE's 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, citing the lack of timeliness of 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, consistent with its November 16, 2017 order.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and refund TCJA transmission-related income tax regulatory liabilities for the prospective period starting on October 1, 2018. In addition, on October 9, 2018,filing by ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order. for similar recovery.
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. On March 27, 2020, the Court of Appeals denied BGE’s November 2, 2018 appeal.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover only 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 ACE cannot predictother parties filed a settlement agreement with FERC, which FERC approved on September 24, 2020. The settlement agreement provides for the outcomerecovery of these proceedings.
If FERC ultimately rules thatongoing transmission-related income tax regulatory assets and establishes the future, ongoing non-TCJAamount and amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPLperiod for excess deferred income taxes resulting from TCJA. The settlement resulted in a reduction to Operating revenues and ACE would record additional chargesan offsetting reduction to Income tax expense which could be up to approximately $80 million, $52 million, $16 million, $12 million, $4 million, $6 million and $2 million, respectively, asin the second quarter of September 30, 2019.2020.
Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2018,2019, unless noted below. See Note 43 — Regulatory Matters of the Exelon 20182019 Form 10-K for additional information on the specific regulatory assets and liabilities.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 62 — Regulatory Matters
ComEdPECO. . Regulatory assets increased $122$135 million primarily due to an increase of $186$119 million in Energy Efficiency Costs and $32 million Renewable Energy partially offset by a decrease of $97 million in Electric Distribution Formula Rate Annual Reconciliations.
PECO. Regulatory assets increased $62 million primarily due to an increase of $95 million inthe Deferred Income Taxes offset by a $34regulatory asset and $20 million decrease in Electric Energy and Natural Gas Costs.new COVID-19 regulatory asset recorded in the third quarter of 2020. Refer to COVID-19 disclosure below for additional information.
BGE. Regulatory liabilities decreased $90 million primarily due to a decrease of $40 million in Deferred Income Taxes and $43 million in Removal Costs.
Pepco. Regulatory assets decreased $84 million primarily due to a decrease of $39 million in Electric Energy and Natural Gas Costs, $26 million in DC PLUG charge and $14 million in AMI Programs - Deployment Costs and Legacy Meters. Regulatory liabilities decreased by $71$68 million primarily due to a decrease of $73 million in the Deferred Income Taxes.Taxes regulatory liability.
DPL.Pepco. Regulatory liabilities decreased $42$58 million primarily due to a decrease of $29$99 million in the Deferred Income Taxes regulatory liability, partially offset by a $24 million increase in the Transmission FERC Formula Rate regulatory liability, and $10$24 million in the Electric Energy and Natural Gas Costs.Costs regulatory liability.
ACE.DPL. Regulatory liabilities decreased $30$49 million primarily due to a decrease of $32$54 million in the Deferred Income Taxes.Taxes regulatory liability, $4 million in the Removal Costs regulatory liability, and $3 million in the Electric Energy and Natural Gas Costs regulatory liability, partially offset by a $16 million increase in the Transmission FERC Formula Rate regulatory liability.
ACE. Regulatory assets increased $58 million primarily due to an increase of $29 million in the Deferred Storm Costs regulatory asset, $19 million in the Uncollectible Deferral regulatory asset, and $17 million in the Electric Energy Costs regulatory asset, partially offset by a decrease of $9 million in the Securitized Stranded Costs regulatory asset. Regulatory liabilities decreased $55 million primarily due to a decrease of $80 million in the Deferred Income Taxes regulatory liability, partially offset by a $13 million increase in Transmission FERC Formula Rate regulatory liability, and $9 million in Stranded Costs regulatory liability.
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, they are expected to continue through the first quarter of 2021 in other jurisdictions. Typically, the Utility Registrants recover credit loss expense through rate 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 rate 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. The Utility Registrants expect to seek recovery in upcoming distribution base rate cases. Exelon and the Utility Registrants recorded the following regulatory assets related to COVID-19:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| September 30, 2020 | $ | 60 | | | $ | 18 | | | $ | 20 | | | $ | 11 | | | $ | 11 | | | $ | 8 | | | $ | 3 | | | $ | 0 | |
Capitalized Ratemaking Amounts Not Recognized (Exelon and the Utility Registrants)
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 |
| September 30, 2019 | $ | 59 |
| | $ | 4 |
| | $ | — |
| | $ | 47 |
| | $ | 8 |
| | $ | 5 |
| | $ | 3 |
| | $ | — |
|
| December 31, 2018 | $ | 65 |
| | $ | 8 |
| | $ | — |
| | $ | 49 |
| | $ | 8 |
| | $ | 5 |
| | $ | 3 |
| | $ | — |
|
_________
| |
(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. |
Generation Regulatory Matters (Exelon and Generation)
Illinois Regulatory Matters63
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. During the first quarter of 2018, Generation recognized $150 million of revenue 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. The lawsuits were dismissed by the district court on July 14, 2017. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court's dismissal of both lawsuits. On January 7, 2019, plaintiffs filed a petition seeking U.S. Supreme Court review of the case, which was denied on April 15, 2019.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 62 — Regulatory Matters
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | ComEd(a) | | PECO | | BGE(b) | | PHI | | Pepco(c) | | DPL(c) | | ACE |
| September 30, 2020 | $ | 54 | | | $ | 0 | | | $ | 0 | | | $ | 47 | | | $ | 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.
Generation Regulatory Matters (Exelon and Generation)
New Jersey Regulatory Matters
New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that will provideprovides 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 November 19, 2018, 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 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 $21$56 million and $31 million for the three and nine months ended September 30, 2019.2020 and 2019, respectively. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU's decision to the New Jersey Superior Court. The appeal does not prevent implementation of the ZEC program.Briefing has been completed and oral argument is scheduled for December 9, 2020. Exelon and Generation cannot predict the outcome of the appeal. See Note 86 — Early Plant Retirements for additional information related to Salem.
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.NYPSC to be Generation's FitzPatrick, Ginna, and Nine Mile Point nuclear facilities.
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, which was dismissed by the district court on July 25, 2017. 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 U.S. Supreme Court review of the case which was denied on April 15, 2019.
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. On October 8, 2019, the court dismissed all remaining claims. The petitioners havefiled a notice of appeal on November 4, 2019 and originally had until November 11, 2019May 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 notice of appeal.motion to vacate the dismissal if they can show good cause for the delay.
See Note 86 — 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
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. 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 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. 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, 2020, Generation filed a request for rehearing with FERC. The timing and the outcome of this proceeding is uncertain.
See Note 6 — Early Plant Retirements and Note 8 — 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 2 — Regulatory Matters
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 accepted 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 but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before FERC in another proceeding.
FERC issued an order on May 21, 2020 involving reforms to PJM’s day-ahead and real-time reserves markets that need to be reflected in the calculation of MOPR levels. In approving reforms to PJM’s reserves markets, FERC also directed PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services (referred to as the Energy and Ancillary Services Offset) and to use that new methodology in calculating a number of parameters and assumptions used in the capacity market, including MOPR levels. PJM submitted all elements of its new Energy and Ancillary Services Offset revenue projection methodology on August 5, 2020. On review of this compliance filing, FERC is expected to address how these additional reforms will impact MOPR levels, the timeline for implementing the new revenue projection methodology, and the timing for commencing the capacity auction schedule.
Unless Illinois and New Jersey can implement an FRR program in their PJM zones, the MOPR will apply in the 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 6 - 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.
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 plans to strenuously oppose expansion of FERC’s MOPR policies in the NYISO market. While it is too early in the proceeding to predict its outcome, 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 62 — Regulatory Matters
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 entered intofiled with FERC a settlement agreement (MDEJoint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. UnderPursuant to the MDEOffer of Settlement, the parties will propose license articlessubmitted Proposed License Articles to FERC for approval as an offer of settlement to be incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act. The MDE Settlement provides that ifAmong 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 offerOffer of settlement,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, including modifications to river flows to improve aquatic habitat, along with other additional fish and eel passage improvements and initiatives to support rare, threatened and endangered wildlife, among other commitments. Exelon’s commitments under the DOIvarious provisions of the Offer of Settlement and MDE SettlementsSettlement are not effective unless and until incorporated by FERC intoapproves the new license.
The financial impactOffer of the DOISettlement and MDE Settlements and other anticipated license commitments are estimated to be $11 million to $14 million per year, on average, recognized overissues the new license term, including capital and operating costs. The actual timing and amount ofwith the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license.Proposed License Articles. Generation cannot currently predict when FERC will issue the new license.
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.
3. 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.
See Note 4 — Revenue from Contracts with Customers of the Exelon 2019 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.
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 provides a rollforward of the contract assets reflected in Exelon's and Generation's Consolidated Balance Sheets for the three and nine months ended September 30, 2020 and 2019. 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)
Note 3 — Revenue from Contracts with Customers
| | | | | | | | | | | | | | | | | | |
| | | | |
| | Exelon | | Generation | | | | |
| Balance as of December 31, 2019 | | $ | 174 | | | $ | 174 | | | | | |
| Amounts reclassified to receivables | | (19) | | | (19) | | | | | |
| Revenues recognized | | 17 | | | 17 | | | | | |
| Balance at March 31, 2020 | | $ | 172 | | | $ | 172 | | | | | |
| Amounts reclassified to receivables | | (26) | | | (26) | | | | | |
| Revenues recognized | | 13 | | | 13 | | | | | |
| Balance at June 30, 2020 | | $ | 159 | | | $ | 159 | | | | | |
| Amounts reclassified to receivables | | (18) | | | (18) | | | | | |
| Revenues recognized | | 19 | | | 19 | | | | | |
| Balance at September 30, 2020 | | $ | 160 | | | $ | 160 | | | | | |
| | | | | | | | |
| | | | | | | | |
| | Exelon | | Generation | | | | |
| Balance as of December 31, 2018 | | $ | 187 | | | $ | 187 | | | | | |
| Amounts reclassified to receivables | | (26) | | | (26) | | | | | |
| Revenues recognized | | 26 | | | 26 | | | | | |
| Balance at March 31, 2019 | | $ | 187 | | | $ | 187 | | | | | |
| Amounts reclassified to receivables | | (18) | | | (18) | | | | | |
| Revenues recognized | | 27 | | | 27 | | | | | |
| Balance at June 30, 2019 | | $ | 196 | | | $ | 196 | | | | | |
| Amounts reclassified to receivables | | (65) | | | (65) | | | | | |
| Revenues recognized | | 39 | | | 39 | | | | | |
| Balance at September 30, 2019 | | $ | 170 | | | $ | 170 | | | | | |
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.
On July 1, 2020, Pepco, DPL, and ACE each entered into a collaborative arrangement with an unrelated owner and manager of communication infrastructure (the Buyer). Under this arrangement, Pepco, DPL, and ACE sold a 60% undivided interest in their respective portfolios of transmission tower attachment agreements with telecommunications companies to the Buyer, in addition to transitioning management of the day-to-day operations of the jointly-owned agreements to the Buyer for 35 years, while retaining the safe and reliable operation of its utility assets. In return, Pepco, DPL, and ACE will provide the Buyer limited access on the portion of the towers where the equipment resides for the purposes of managing the agreements for the benefit of Pepco, DPL, ACE, and the Buyer. 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 received cash and recorded contract liabilities as of July 1, 2020 as shown in the table below. The revenue attributable to this arrangement will be recognized as operating revenue over the 35 years under the collaborative arrangement.
The following table 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 for the three and nine months ended September 30, 2020 and 2019. As of September 30, 2020 and December 31, 2019, $41 millionComEd's, PECO's, and BGE's contract liabilities were immaterial.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 3 — Revenue from Contracts with Customers
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | Exelon | | Generation | | PHI | | Pepco | | DPL | | ACE |
| Balance as of December 31, 2019 | | $ | 33 | | | $ | 71 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Consideration received or due | | 20 | | | 55 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Revenues recognized | | (24) | | | (70) | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance at March 31, 2020 | | $ | 29 | | | $ | 56 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Consideration received or due | | 13 | | | 34 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Revenues recognized | | (22) | | | (63) | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance at June 30, 2020 | | $ | 20 | | | $ | 27 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Consideration received or due | | 154 | | | 94 | | | 124 | | | 98 | | | 13 | | | 13 | |
| Revenues recognized | | (25) | | | (65) | | | (2) | | | (2) | | | 0 | | | 0 | |
| Balance at September 30, 2020 | | $ | 149 | | | $ | 56 | | | $ | 122 | | | $ | 96 | | | $ | 13 | | | $ | 13 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | Exelon | | Generation | | PHI | | Pepco | | DPL | | ACE |
| Balance as of December 31, 2018 | | $ | 27 | | | $ | 42 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Consideration received or due | | 21 | | | 63 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Revenues recognized | | (23) | | | (66) | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance at March 31, 2019 | | $ | 25 | | | $ | 39 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Consideration received or due | | 17 | | | 52 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Revenues recognized | | (21) | | | (65) | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance at June 30, 2019 | | $ | 21 | | | $ | 26 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Consideration received or due | | 27 | | | 83 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Revenues recognized | | (22) | | | (61) | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance at September 30, 2019 | | $ | 26 | | | $ | 48 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
The following table reflects revenues recognized in the three and nine months ended September 30, 2020 and 2019, which were included in contract liabilities at December 31, 2019 and 2018, respectively:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
| Exelon | $ | 2 | | | $ | 3 | | | $ | 25 | | | $ | 17 | |
| Generation | 2 | | | 3 | | | 63 | | | 32 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
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 September 30, 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 3 — Revenue from Contracts with Customers
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2021 | | 2022 | | 2023 | | 2024 and thereafter | | Total |
| Exelon | $ | 92 | | | $ | 223 | | | $ | 93 | | | $ | 53 | | | $ | 370 | | | $ | 831 | |
| Generation | 136 | | | 313 | | | 123 | | | 53 | | | 275 | | | 900 | |
| PHI | 2 | | | 9 | | | 8 | | | 8 | | | 95 | | | 122 | |
| Pepco | 2 | | | 7 | | | 6 | | | 6 | | | 75 | | | 96 | |
| DPL | 0 | | | 1 | | | 1 | | | 1 | | | 10 | | | 13 | |
| ACE | 0 | | | 1 | | | 1 | | | 1 | | | 10 | | | 13 | |
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 4 — Segment Information for the presentation of the Registrant's revenue disaggregation.
4. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources at each of the Registrants.
Exelon has 11 reportable segments, which include Generation's 5 reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, and PHI's 3 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 5 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.
•New York represents operations within NYISO.
•ERCOT represents operations within Electric Reliability Council of Texas.
•Other Power Regions:
•New England represents the operations within ISO-NE.
•South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM.
•West represents operations in the WECC, which includes California ISO.
•Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
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 measurement of operational performance. RNF 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. 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 Conowingo licensing effortsthe 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 results of Generation'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 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 making decisions regarding allocating resources to or assessing the performance of these reportable segments.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2020 and 2019 is as follows:
Three Months Ended September 30, 2020 and 2019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
Operating revenues(b): |
| 2020 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 4,201 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | (326) | | | $ | 3,875 | |
| Competitive businesses natural gas revenues | 323 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 323 | |
| Competitive businesses other revenues | 135 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (3) | | | 132 | |
| Rate-regulated electric revenues | 0 | | | 1,643 | | | 759 | | | 646 | | | 1,339 | | | 0 | | | (22) | | | 4,365 | |
| Rate-regulated natural gas revenues | 0 | | | 0 | | | 54 | | | 85 | | | 23 | | | 0 | | | (3) | | | 159 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 0 | | | 6 | | | 484 | | | (491) | | | (1) | |
| Total operating revenues | $ | 4,659 | | | $ | 1,643 | | | $ | 813 | | | $ | 731 | | | $ | 1,368 | | | $ | 484 | | | $ | (845) | | | $ | 8,853 | |
| 2019 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 4,314 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | (275) | | | $ | 4,039 | |
| Competitive businesses natural gas revenues | 265 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 1 | | | 266 | |
| Competitive businesses other revenues | 195 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (1) | | | 194 | |
| Rate-regulated electric revenues | 0 | | | 1,583 | | | 716 | | | 619 | | | 1,357 | | | 0 | | | (7) | | | 4,268 | |
| Rate-regulated natural gas revenues | 0 | | | 0 | | | 62 | | | 84 | | | 20 | | | 0 | | | (3) | | | 163 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 0 | | | 3 | | | 474 | | | (478) | | | (1) | |
| Total operating revenues | $ | 4,774 | | | $ | 1,583 | | | $ | 778 | | | $ | 703 | | | $ | 1,380 | | | $ | 474 | | | $ | (763) | | | $ | 8,929 | |
| | | | | | | | | | | | | | | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
Intersegment revenues(c): | | | | | | | | | | | | | | | |
| 2020 | $ | 331 | | | $ | 15 | | | $ | 3 | | | $ | 6 | | | $ | 6 | | | $ | 485 | | | $ | (845) | | | $ | 1 | |
| 2019 | 275 | | | 4 | | | 1 | | | 6 | | | 4 | | | 474 | | | (764) | | | 0 | |
| Depreciation and amortization: | | | | | | | | | | | | | | | |
| 2020 | $ | 558 | | | $ | 294 | | | $ | 85 | | | $ | 133 | | | $ | 200 | | | $ | 19 | | | $ | 0 | | | $ | 1,289 | |
| 2019 | 407 | | | 259 | | | 83 | | | 116 | | | 193 | | | 25 | | | 0 | | | 1,083 | |
| Operating expenses: | | | | | | | | | | | | | | | |
| 2020 | $ | 4,727 | | | $ | 1,302 | | | $ | 658 | | | $ | 642 | | | $ | 1,102 | | | $ | 489 | | | $ | (833) | | | $ | 8,087 | |
| 2019 | 4,274 | | | 1,256 | | | 595 | | | 612 | | | 1,124 | | | 457 | | | (759) | | | 7,559 | |
| Interest expense, net: | | | | | | | | | | | | | | | |
| 2020 | $ | 80 | | | $ | 95 | | | $ | 39 | | | $ | 34 | | | $ | 67 | | | $ | 89 | | | $ | 0 | | | $ | 404 | |
| 2019 | 109 | | | 91 | | | 33 | | | 31 | | | 66 | | | 79 | | | 0 | | | 409 | |
| Income (loss) before income taxes: | | | | | | | | | | | | | | | |
| 2020 | $ | 219 | | | $ | 256 | | | $ | 122 | | | $ | 61 | | | $ | 215 | | | $ | (87) | | | $ | 0 | | | $ | 786 | |
| 2019 | 501 | | | 245 | | | 154 | | | 67 | | | 203 | | | (68) | | | 0 | | | 1,102 | |
| Income Taxes: | | | | | | | | | | | | | | | |
| 2020 | $ | 100 | | | $ | 60 | | | $ | (16) | | | $ | 8 | | | $ | (1) | | | $ | 65 | | | $ | 0 | | | $ | 216 | |
| 2019 | 87 | | | 45 | | | 14 | | | 12 | | | 14 | | | 0 | | | 0 | | | 172 | |
| Net income (loss): | | | | | | | | | | | | | | | |
| 2020 | $ | 117 | | | $ | 196 | | | $ | 138 | | | $ | 53 | | | $ | 216 | | | $ | (151) | | | $ | 0 | | | $ | 569 | |
| 2019 | 244 | | | 200 | | | 140 | | | 55 | | | 189 | | | (68) | | | 0 | | | 760 | |
| Capital Expenditures: | | | | | | | | | | | | | | | |
| 2020 | $ | 282 | | | $ | 554 | | | $ | 312 | | | $ | 290 | | | $ | 386 | | | $ | 9 | | | $ | 0 | | | $ | 1,833 | |
| 2019 | 392 | | | 452 | | | 228 | | | 300 | | | 308 | | | 7 | | | 0 | | | 1,687 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
__________
(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 utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional 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 services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Related Party Transactions for additional information on intersegment revenues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
PHI:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pepco | | DPL | | ACE | | Other(a) | | Intersegment
Eliminations | | PHI |
Operating revenues(b): | | | | | | | | | | | |
| 2020 | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 611 | | | $ | 314 | | | $ | 420 | | | $ | 0 | | | $ | (6) | | | $ | 1,339 | |
| Rate-regulated natural gas revenues | 0 | | | 23 | | | 0 | | | 0 | | | 0 | | | 23 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 91 | | | (85) | | | 6 | |
| Total operating revenues | $ | 611 | | | $ | 337 | | | $ | 420 | | | $ | 91 | | | $ | (91) | | | $ | 1,368 | |
| 2019 | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 642 | | | $ | 299 | | | $ | 419 | | | $ | 0 | | | $ | (3) | | | $ | 1,357 | |
| Rate-regulated natural gas revenues | 0 | | | 20 | | | 0 | | | 0 | | | 0 | | | 20 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 92 | | | (89) | | | 3 | |
| Total operating revenues | $ | 642 | | | $ | 319 | | | $ | 419 | | | $ | 92 | | | $ | (92) | | | $ | 1,380 | |
Intersegment revenues(c): | | | | | | | | | | | |
| 2020 | $ | 3 | | | $ | 3 | | | $ | 1 | | | $ | 90 | | | $ | (91) | | | $ | 6 | |
| 2019 | 2 | | | 1 | | | 1 | | | 93 | | | (93) | | | 4 | |
| Depreciation and amortization: | | | | | | | | | | | |
| 2020 | $ | 96 | | | $ | 48 | | | $ | 48 | | | $ | 8 | | | $ | 0 | | | $ | 200 | |
| 2019 | 95 | | | 46 | | | 43 | | | 9 | | | 0 | | | 193 | |
| Operating expenses: | | | | | | | | | | | |
| 2020 | $ | 465 | | | $ | 296 | | | $ | 338 | | | $ | 94 | | | $ | (91) | | | $ | 1,102 | |
| 2019 | 515 | | | 268 | | | 340 | | | 95 | | | (94) | | | 1,124 | |
| Interest expense, net: | | | | | | | | | | | |
| 2020 | $ | 35 | | | $ | 15 | | | $ | 15 | | | $ | 2 | | | $ | 0 | | | $ | 67 | |
| 2019 | 33 | | | 15 | | | 15 | | | 3 | | | 0 | | | 66 | |
| Income (loss) before income taxes: | | | | | | | | | | | |
| 2020 | $ | 121 | | | $ | 28 | | | $ | 68 | | | $ | (2) | | | $ | 0 | | | $ | 215 | |
2019(d) | 103 | | | 38 | | | 65 | | | (3) | | | 0 | | | 203 | |
| Income Taxes: | | | | | | | | | | | |
| 2020 | $ | 3 | | | $ | 1 | | | $ | (7) | | | $ | 2 | | | $ | 0 | | | $ | (1) | |
| 2019 | 5 | | | 5 | | | 2 | | | 2 | | | 0 | | | 14 | |
| Net income (loss): | | | | | | | | | | | |
| 2020 | $ | 118 | | | $ | 27 | | | $ | 75 | | | $ | (4) | | | $ | 0 | | | $ | 216 | |
| 2019 | 98 | | | 33 | | | 63 | | | (5) | | | 0 | | | 189 | |
| Capital Expenditures: | | | | | | | | | | | |
| 2020 | $ | 188 | | | $ | 94 | | | $ | 103 | | | $ | 1 | | | $ | 0 | | | $ | 386 | |
| 2019 | 157 | | | 85 | | | 73 | | | (7) | | | 0 | | | 308 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
__________
(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 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 17 — Supplemental 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 amounts in Other and Intersegment Eliminations have been capitalized.adjusted by an offsetting $195 million for consistency with the Exelon 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 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
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):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| Three Months Ended September 30, 2020 |
| Revenues from external customers(a) | | Intersegment
Revenues | | Total
Revenues |
| Contracts with customers | | Other(b) | | Total | | |
| Mid-Atlantic | $ | 1,327 | | | $ | (20) | | | $ | 1,307 | | | $ | 6 | | | $ | 1,313 | |
| Midwest | 974 | | | 68 | | | 1,042 | | | 1 | | | 1,043 | |
| New York | 401 | | | 5 | | | 406 | | | 0 | | | 406 | |
| ERCOT | 249 | | | 74 | | | 323 | | | 7 | | | 330 | |
| Other Power Regions | 937 | | | 186 | | | 1,123 | | | (14) | | | 1,109 | |
| Total Competitive Businesses Electric Revenues | 3,888 | | | 313 | | | 4,201 | | | 0 | | | 4,201 | |
| Competitive Businesses Natural Gas Revenues | 169 | | | 154 | | | 323 | | | 0 | | | 323 | |
Competitive Businesses Other Revenues(c) | 85 | | | 50 | | | 135 | | | 0 | | | 135 | |
| Total Generation Consolidated Operating Revenues | $ | 4,142 | | | $ | 517 | | | $ | 4,659 | | | $ | 0 | | | $ | 4,659 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| Three Months Ended September 30, 2019 |
| Revenues from external customers(a) | | Intersegment
revenues | | Total
Revenues |
| Contracts with customers | | Other(b) | | Total | | |
| Mid-Atlantic | $ | 1,351 | | | $ | 10 | | | $ | 1,361 | | | $ | 3 | | | $ | 1,364 | |
| Midwest | 1,052 | | | 47 | | | 1,099 | | | (17) | | | 1,082 | |
| New York | 414 | | | 15 | | | 429 | | | 0 | | | 429 | |
| ERCOT | 288 | | | 72 | | | 360 | | | 5 | | | 365 | |
| Other Power Regions | 873 | | | 192 | | | 1,065 | | | (25) | | | 1,040 | |
| Total Competitive Businesses Electric Revenues | 3,978 | | | 336 | | | 4,314 | | | (34) | | | 4,280 | |
| Competitive Businesses Natural Gas Revenues | 160 | | | 105 | | | 265 | | | 34 | | | 299 | |
Competitive Businesses Other Revenues(c) | 112 | | | 83 | | | 195 | | | 0 | | | 195 | |
| Total Generation Consolidated Operating Revenues | $ | 4,250 | | | $ | 524 | | | $ | 4,774 | | | $ | 0 | | | $ | 4,774 | |
__________
(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 unrealized mark-to-market gains of $37 million and $77 million in 2020 and 2019, respectively, and the elimination of intersegment revenues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
Revenues net of purchased power and fuel expense (Generation):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| Three Months Ended September 30, 2020 | | Three Months Ended September 30, 2019 |
| RNF from external customers(a) | | Intersegment
RNF | | Total RNF | | RNF from external customers(a) | | Intersegment
RNF | | Total RNF |
| Mid-Atlantic | $ | 586 | | | $ | 5 | | | $ | 591 | | | $ | 684 | | | $ | 5 | | | $ | 689 | |
| Midwest | 748 | | | 2 | | | 750 | | | 763 | | | (16) | | | 747 | |
| New York | 281 | | | 4 | | | 285 | | | 288 | | | 3 | | | 291 | |
| ERCOT | 141 | | | 6 | | | 147 | | | 76 | | | (4) | | | 72 | |
| Other Power Regions | 253 | | | (28) | | | 225 | | | 212 | | | (28) | | | 184 | |
| Total Revenues net of purchased power and fuel expense for Reportable Segments | 2,009 | | | (11) | | | 1,998 | | | 2,023 | | | (40) | | | 1,983 | |
Other(b) | 336 | | | 11 | | | 347 | | | 100 | | | 40 | | | 140 | |
| Total Generation Revenues net of purchased power and fuel expense | $ | 2,345 | | | $ | 0 | | | $ | 2,345 | | | $ | 2,123 | | | $ | 0 | | | $ | 2,123 | |
__________
(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 unrealized mark-to-market gains of $255 million and $17 million in 2020 and 2019, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 6 - Early Plant Retirements of $24 million, which includes an impairment charge of $10 million, and $3 million decrease to revenue net of purchased power and fuel expense in 2020 and 2019, respectively, and the elimination of intersegment RNF.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
Electric and Gas Revenue by Customer Class (Utility Registrants):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Three Months Ended September 30, 2020 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 920 | | | $ | 518 | | | $ | 389 | | | $ | 763 | | | $ | 307 | | | $ | 193 | | | $ | 263 | |
| Small commercial & industrial | 379 | | | 104 | | | 65 | | | 134 | | | 36 | | | 45 | | | 53 | |
| Large commercial & industrial | 135 | | | 66 | | | 113 | | | 262 | | | 195 | | | 21 | | | 46 | |
| Public authorities & electric railroads | 10 | | | 7 | | | 7 | | | 14 | | | 8 | | | 3 | | | 3 | |
Other(a) | 234 | | | 58 | | | 78 | | | 141 | | | 47 | | | 44 | | | 50 | |
Total rate-regulated electric revenues(b) | $ | 1,678 | | | $ | 753 | | | $ | 652 | | | $ | 1,314 | | | $ | 593 | | | $ | 306 | | | $ | 415 | |
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | 0 | | | $ | 32 | | | $ | 55 | | | $ | 11 | | | $ | 0 | | | $ | 11 | | | $ | 0 | |
| Small commercial & industrial | 0 | | | 16 | | | 9 | | | 6 | | | 0 | | | 6 | | | 0 | |
| Large commercial & industrial | 0 | | | 0 | | | 21 | | | 1 | | | 0 | | | 1 | | | 0 | |
| Transportation | 0 | | | 6 | | | 0 | | | 3 | | | 0 | | | 3 | | | 0 | |
Other(c) | 0 | | | 1 | | | 3 | | | 2 | | | 0 | | | 2 | | | 0 | |
Total rate-regulated natural gas revenues(d) | $ | 0 | | | $ | 55 | | | $ | 88 | | | $ | 23 | | | $ | 0 | | | $ | 23 | | | $ | 0 | |
| Total rate-regulated revenues from contracts with customers | $ | 1,678 | | | $ | 808 | | | $ | 740 | | | $ | 1,337 | | | $ | 593 | | | $ | 329 | | | $ | 415 | |
| | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (38) | | | $ | 5 | | | $ | (9) | | | $ | 31 | | | $ | 18 | | | $ | 8 | | | $ | 5 | |
Other rate-regulated electric revenues(e) | 3 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Other rate-regulated natural gas revenues(e) | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | |
| Total other revenues | $ | (35) | | | $ | 5 | | | $ | (9) | | | $ | 31 | | | $ | 18 | | | $ | 8 | | | $ | 5 | |
| Total rate-regulated revenues for reportable segments | $ | 1,643 | | | $ | 813 | | | $ | 731 | | | $ | 1,368 | | | $ | 611 | | | $ | 337 | | | $ | 420 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Three Months Ended September 30, 2019 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 865 | | | $ | 479 | | | $ | 352 | | | $ | 741 | | | $ | 311 | | | $ | 178 | | | $ | 252 | |
| Small commercial & industrial | 393 | | | 109 | | | 64 | | | 147 | | | 41 | | | 48 | | | 58 | |
| Large commercial & industrial | 141 | | | 63 | | | 116 | | | 297 | | | 222 | | | 26 | | | 49 | |
| Public authorities & electric railroads | 12 | | | 9 | | | 7 | | | 17 | | | 11 | | | 3 | | | 3 | |
Other(a) | 222 | | | 63 | | | 82 | | | 164 | | | 58 | | | 50 | | | 56 | |
Total rate-regulated electric revenues(b) | $ | 1,633 | | | $ | 723 | | | $ | 621 | | | $ | 1,366 | | | $ | 643 | | | $ | 305 | | | $ | 418 | |
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | 0 | | | $ | 38 | | | $ | 49 | | | $ | 9 | | | $ | 0 | | | $ | 9 | | | $ | 0 | |
| Small commercial & industrial | 0 | | | 17 | | | 9 | | | 4 | | | 0 | | | 4 | | | 0 | |
| Large commercial & industrial | 0 | | | 0 | | | 20 | | | 1 | | | 0 | | | 1 | | | 0 | |
| Transportation | 0 | | | 5 | | | 0 | | | 4 | | | 0 | | | 4 | | | 0 | |
Other(c) | 0 | | | 2 | | | 5 | | | 2 | | | 0 | | | 2 | | | 0 | |
Total rate-regulated natural gas revenues(d) | $ | 0 | | | $ | 62 | | | $ | 83 | | | $ | 20 | | | $ | 0 | | | $ | 20 | | | $ | 0 | |
| Total rate-regulated revenues from contracts with customers | $ | 1,633 | | | $ | 785 | | | $ | 704 | | | $ | 1,386 | | | $ | 643 | | | $ | 325 | | | $ | 418 | |
| | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (56) | | | $ | (11) | | | $ | (5) | | | $ | (9) | | | $ | (3) | | | $ | (6) | | | $ | 1 | |
Other rate-regulated electric revenues(e) | 6 | | | 4 | | | 3 | | | 3 | | | 2 | | | 0 | | | 0 | |
Other rate-regulated natural gas revenues(e) | 0 | | | 0 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | |
| Total other revenues | $ | (50) | | | $ | (7) | | | $ | (1) | | | $ | (6) | | | $ | (1) | | | $ | (6) | | | $ | 1 | |
| Total rate-regulated revenues for reportable segments | $ | 1,583 | | | $ | 778 | | | $ | 703 | | | $ | 1,380 | | | $ | 642 | | | $ | 319 | | | $ | 419 | |
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $15 million, $3 million, $3 million, $6 million, $3 million, $3 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, respectively, in 2020 and $4 million, $1 million, $2 million, $4 million, $2 million, $1 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, respectively, in 2019.
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates of less than $1 million and $3 million at PECO and BGE, respectively, in 2020 and less than $1 million and $4 million at PECO and BGE, respectively, in 2019.
(e)Includes late payment charge revenues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
Nine Months Ended September 30, 2020 and 2019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
Operating revenues(b): |
| 2020 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 11,367 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | (920) | | | $ | 10,447 | |
| Competitive businesses natural gas revenues | 1,348 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (3) | | | 1,345 | |
| Competitive businesses other revenues | 557 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (5) | | | 552 | |
| Rate-regulated electric revenues | 0 | | | 4,499 | | | 1,948 | | | 1,763 | | | 3,425 | | | 0 | | | (50) | | | 11,585 | |
| Rate-regulated natural gas revenues | 0 | | | 0 | | | 358 | | | 521 | | | 116 | | | 0 | | | (5) | | | 990 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 0 | | | 13 | | | 1,440 | | | (1,447) | | | 6 | |
| Total operating revenues | $ | 13,272 | | | $ | 4,499 | | | $ | 2,306 | | | $ | 2,284 | | | $ | 3,554 | | | $ | 1,440 | | | $ | (2,430) | | | $ | 24,925 | |
| 2019 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 12,365 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | (840) | | | $ | 11,525 | |
| Competitive businesses natural gas revenues | 1,479 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 1,479 | |
| Competitive businesses other revenues | 436 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (4) | | | 432 | |
| Rate-regulated electric revenues | 0 | | | 4,342 | | | 1,901 | | | 1,817 | | | 3,574 | | | 0 | | | (25) | | | 11,609 | |
| Rate-regulated natural gas revenues | 0 | | | 0 | | | 432 | | | 510 | | | 116 | | | 0 | | | (12) | | | 1,046 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 0 | | | 10 | | | 1,410 | | | (1,415) | | | 5 | |
| Total operating revenues | $ | 14,280 | | | $ | 4,342 | | | $ | 2,333 | | | $ | 2,327 | | | $ | 3,700 | | | $ | 1,410 | | | $ | (2,296) | | | $ | 26,096 | |
| | | | | | | | | | | | | | | |
Intersegment revenues(c): | | | | | | | | | | | | | | | |
| 2020 | $ | 932 | | | $ | 31 | | | $ | 7 | | | $ | 16 | | | $ | 13 | | | $ | 1,435 | | | $ | (2,430) | | | $ | 4 | |
| 2019 | 844 | | | 13 | | | 4 | | | 18 | | | 11 | | | 1,410 | | | (2,300) | | | 0 | |
| Depreciation and amortization: | | | | | | | | | | | | | | | |
| 2020 | $ | 1,161 | | | $ | 841 | | | $ | 259 | | | $ | 405 | | | $ | 585 | | | $ | 61 | | | $ | 0 | | | $ | 3,312 | |
| 2019 | 1,221 | | | 767 | | | 247 | | | 368 | | | 562 | | | 72 | | | 0 | | | 3,237 | |
| Operating expenses: | | | | | | | | | | | | | | | |
| 2020 | $ | 12,674 | | | $ | 3,798 | | | $ | 1,900 | | | $ | 1,903 | | | $ | 3,057 | | | $ | 1,452 | | | $ | (2,397) | | | $ | 22,387 | |
| 2019 | 13,333 | | | 3,431 | | | 1,783 | | | 1,936 | | | 3,106 | | | 1,405 | | | (2,291) | | | 22,703 | |
| Interest expense, net: | | | | | | | | | | | | | | | |
| 2020 | $ | 277 | | | $ | 287 | | | $ | 108 | | | $ | 99 | | | $ | 201 | | | $ | 269 | | | $ | 0 | | | $ | 1,241 | |
| 2019 | 336 | | | 268 | | | 100 | | | 89 | | | 197 | | | 231 | | | 0 | | | 1,221 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other(a) | | Intersegment
Eliminations | | Exelon |
| Income (loss) before income taxes: | | | | | | | | | | | | | | | |
| 2020 | $ | 532 | | | $ | 446 | | | $ | 310 | | | $ | 299 | | | $ | 340 | | | $ | (262) | | | $ | 0 | | | $ | 1,665 | |
| 2019 | 1,355 | | | 674 | | | 461 | | | 320 | | | 436 | | | (218) | | | 0 | | | 3,028 | |
| Income Taxes: | | | | | | | | | | | | | | | |
| 2020 | $ | 41 | | | $ | 142 | | | $ | (7) | | | $ | 26 | | | $ | (77) | | | $ | 16 | | | $ | 0 | | | $ | 141 | |
| 2019 | 388 | | | 130 | | | 51 | | | 59 | | | 25 | | | (27) | | | 0 | | | 626 | |
| Net income (loss): | | | | | | | | | | | | | | | |
| 2020 | $ | 485 | | | $ | 304 | | | $ | 317 | | | $ | 273 | | | $ | 418 | | | $ | (278) | | | $ | 0 | | | $ | 1,519 | |
| 2019 | 784 | | | 544 | | | 410 | | | 261 | | | 412 | | | (191) | | | 0 | | | 2,220 | |
| Capital Expenditures: | | | | | | | | | | | | | | | |
| 2020 | $ | 1,212 | | | $ | 1,583 | | | $ | 824 | | | $ | 838 | | | $ | 1,072 | | | $ | 77 | | | $ | 0 | | | $ | 5,606 | |
| 2019 | 1,282 | | | 1,413 | | | 675 | | | 842 | | | 1,006 | | | 41 | | | 0 | | | 5,259 | |
| Total assets: | | | | | | | | | | | | | | | |
| September 30, 2020 | $ | 47,372 | | | $ | 34,243 | | | $ | 12,334 | | | $ | 11,370 | | | $ | 23,394 | | | $ | 9,070 | | | $ | (10,016) | | | $ | 127,767 | |
| December 31, 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 utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional 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 services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Related Party Transactions for additional information on intersegment revenues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
PHI:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pepco | | DPL | | ACE | | Other(a) | | Intersegment
Eliminations | | PHI |
Operating revenues(b): | | | | | | | | | | | |
| 2020 | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 1,650 | | | $ | 838 | | | $ | 952 | | | $ | 0 | | | $ | (15) | | | $ | 3,425 | |
| Rate-regulated natural gas revenues | 0 | | | 116 | | | 0 | | | 0 | | | 0 | | | 116 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 279 | | | (266) | | | 13 | |
| Total operating revenues | $ | 1,650 | | | $ | 954 | | | $ | 952 | | | $ | 279 | | | $ | (281) | | | $ | 3,554 | |
| 2019 | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 1,748 | | | $ | 871 | | | $ | 966 | | | $ | (1) | | | $ | (10) | | | $ | 3,574 | |
| Rate-regulated natural gas revenues | 0 | | | 116 | | | 0 | | | 0 | | | 0 | | | 116 | |
| Shared service and other revenues | 0 | | | 0 | | | 0 | | | 298 | | | (288) | | | 10 | |
| Total operating revenues | $ | 1,748 | | | $ | 987 | | | $ | 966 | | | $ | 297 | | | $ | (298) | | | $ | 3,700 | |
Intersegment revenues(c): | | | | | | | | | | | |
| 2020 | $ | 6 | | | $ | 7 | | | $ | 3 | | | $ | 278 | | | $ | (281) | | | $ | 13 | |
| 2019 | 5 | | | 5 | | | 2 | | | 297 | | | (298) | | | 11 | |
| Depreciation and amortization: | | | | | | | | | | | |
| 2020 | $ | 282 | | | $ | 143 | | | $ | 134 | | | $ | 26 | | | $ | 0 | | | $ | 585 | |
| 2019 | 281 | | | 138 | | | 114 | | | 29 | | | 0 | | | 562 | |
| Operating expenses: | | | | | | | | | | | |
| 2020 | $ | 1,364 | | | $ | 843 | | | $ | 847 | | | $ | 284 | | | $ | (281) | | | $ | 3,057 | |
| 2019 | 1,444 | | | 820 | | | 838 | | | 302 | | | (298) | | | 3,106 | |
| Interest expense, net: | | | | | | | | | | | |
| 2020 | $ | 103 | | | $ | 47 | | | $ | 45 | | | $ | 6 | | | $ | 0 | | | $ | 201 | |
| 2019 | 100 | | | 45 | | | 44 | | | 8 | | | 0 | | | 197 | |
| Income (loss) before income taxes: | | | | | | | | | | | |
| 2020 | $ | 211 | | | $ | 71 | | | $ | 67 | | | $ | (9) | | | $ | 0 | | | $ | 340 | |
2019(d) | 226 | | | 132 | | | 89 | | | (11) | | | 0 | | | 436 | |
| Income Taxes: | | | | | | | | | | | |
| 2020 | $ | (16) | | | $ | (20) | | | $ | (39) | | | $ | (2) | | | $ | 0 | | | $ | (77) | |
| 2019 | 9 | | | 16 | | | 2 | | | (2) | | | 0 | | | 25 | |
| Net income (loss): | | | | | | | | | | | |
| 2020 | $ | 227 | | | $ | 91 | | | $ | 106 | | | $ | (6) | | | $ | 0 | | | $ | 418 | |
| 2019 | 217 | | | 116 | | | 87 | | | (8) | | | 0 | | | 412 | |
| Capital Expenditures: | | | | | | | | | | | |
| 2020 | $ | 512 | | | $ | 278 | | | $ | 281 | | | $ | 1 | | | $ | 0 | | | $ | 1,072 | |
| 2019 | 455 | | | 245 | | | 300 | | | 6 | | | 0 | | | 1,006 | |
| Total assets: | | | | | | | | | | | |
| September 30, 2020 | $ | 9,227 | | | $ | 4,992 | | | $ | 4,201 | | | $ | 5,239 | | | $ | (265) | | | $ | 23,394 | |
December 31, 2019(d) | 8,661 | | | 4,830 | | | 3,933 | | | 5,335 | | | (40) | | | 22,719 | |
__________
(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 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 17 — Supplemental 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 and Total assets amounts in Other and Intersegment Eliminations have been adjusted by an offsetting $422 million and $5.7 billion, respectively, for consistency with the Exelon 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 revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
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):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| Revenues from external customers(a) | | Intersegment
Revenues | | Total
Revenues |
| Contracts with customers | | Other(b) | | Total | | |
| Mid-Atlantic | $ | 3,692 | | | $ | (152) | | | $ | 3,540 | | | $ | 21 | | | $ | 3,561 | |
| Midwest | 2,773 | | | 240 | | | 3,013 | | | (6) | | | 3,007 | |
| New York | 1,074 | | | (12) | | | 1,062 | | | (1) | | | 1,061 | |
| ERCOT | 579 | | | 155 | | | 734 | | | 20 | | | 754 | |
| Other Power Regions | 2,718 | | | 300 | | | 3,018 | | | (34) | | | 2,984 | |
| Total Competitive Businesses Electric Revenues | 10,836 | | | 531 | | | 11,367 | | | 0 | | | 11,367 | |
| Competitive Businesses Natural Gas Revenues | 881 | | | 467 | | | 1,348 | | | 0 | | | 1,348 | |
Competitive Businesses Other Revenues(c) | 268 | | | 289 | | | 557 | | | 0 | | | 557 | |
| Total Generation Consolidated Operating Revenues | $ | 11,985 | | | $ | 1,287 | | | $ | 13,272 | | | $ | 0 | | | $ | 13,272 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| Nine Months Ended September 30, 2019 |
| Revenues from external customers(a) | | Intersegment
revenues | | Total
Revenues |
| Contracts with customers | | Other(b) | | Total | | |
| Mid-Atlantic | $ | 3,798 | | | $ | 9 | | | $ | 3,807 | | | $ | 2 | | | $ | 3,809 | |
| Midwest | 3,083 | | | 172 | | | 3,255 | | | (31) | | | 3,224 | |
| New York | 1,195 | | | 16 | | | 1,211 | | | 0 | | | 1,211 | |
| ERCOT | 594 | | | 198 | | | 792 | | | 13 | | | 805 | |
| Other Power Regions | 2,849 | | | 451 | | | 3,300 | | | (46) | | | 3,254 | |
| Total Competitive Businesses Electric Revenues | 11,519 | | | 846 | | | 12,365 | | | (62) | | | 12,303 | |
| Competitive Businesses Natural Gas Revenues | 1,041 | | | 438 | | | 1,479 | | | 62 | | | 1,541 | |
Competitive Businesses Other Revenues(c) | 343 | | | 93 | | | 436 | | | 0 | | | 436 | |
| Total Generation Consolidated Operating Revenues | $ | 12,903 | | | $ | 1,377 | | | $ | 14,280 | | | $ | 0 | | | $ | 14,280 | |
__________
(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 unrealized mark-to-market gains of $238 million and $64 million in 2020 and 2019, respectively, and elimination of intersegment revenues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
Revenues net of purchased power and fuel expense (Generation):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| Nine Months Ended September 30, 2020 | | Nine Months Ended September 30, 2019 |
| RNF from external customers(a) | | Intersegment
RNF | | Total RNF | | RNF from external customers(a) | | Intersegment
RNF | | Total RNF |
| Mid-Atlantic | $ | 1,660 | | | $ | 23 | | | $ | 1,683 | | | $ | 2,007 | | | $ | 16 | | | $ | 2,023 | |
| Midwest | 2,180 | | | (2) | | | 2,178 | | | 2,269 | | | (22) | | | 2,247 | |
| New York | 714 | | | 11 | | | 725 | | | 800 | | | 10 | | | 810 | |
| ERCOT | 311 | | | 14 | | | 325 | | | 252 | | | (27) | | | 225 | |
| Other Power Regions | 608 | | | (70) | | | 538 | | | 542 | | | (64) | | | 478 | |
| Total Revenues net of purchased power and fuel expense for Reportable Segments | 5,473 | | | (24) | | | 5,449 | | | 5,870 | | | (87) | | | 5,783 | |
Other(b) | 838 | | | 24 | | | 862 | | | 262 | | | 87 | | | 349 | |
| Total Generation Revenues net of purchased power and fuel expense | $ | 6,311 | | | $ | 0 | | | $ | 6,311 | | | $ | 6,132 | | | $ | 0 | | | $ | 6,132 | |
__________
(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 unrealized mark-to-market gains of $472 million and losses of $84 million in 2020 and 2019, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 6 - Early Plant Retirements of $24 million, which includes an impairment charge of $10 million, and $13 million decrease to revenue net of purchased power and fuel expense in 2020 and 2019, respectively, and the elimination of intersegment RNF.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
Electric and Gas Revenue by Customer Class (Utility Registrants):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 2,389 | | | $ | 1,277 | | | $ | 1,034 | | | $ | 1,825 | | | $ | 779 | | | $ | 501 | | | $ | 545 | |
| Small commercial & industrial | 1,067 | | | 291 | | | 183 | | | 355 | | | 101 | | | 127 | | | 127 | |
| Large commercial & industrial | 388 | | | 174 | | | 311 | | | 755 | | | 558 | | | 66 | | | 131 | |
| Public authorities & electric railroads | 33 | | | 21 | | | 20 | | | 45 | | | 25 | | | 10 | | | 10 | |
Other(a) | 663 | | | 171 | | | 233 | | | 471 | | | 166 | | | 148 | | | 159 | |
Total rate-regulated electric revenues(b) | $ | 4,540 | | | $ | 1,934 | | | $ | 1,781 | | | $ | 3,451 | | | $ | 1,629 | | | $ | 852 | | | $ | 972 | |
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | 0 | | | $ | 252 | | | $ | 342 | | | $ | 68 | | | $ | 0 | | | $ | 68 | | | $ | 0 | |
| Small commercial & industrial | 0 | | | 86 | | | 55 | | | 30 | | | 0 | | | 30 | | | 0 | |
| Large commercial & industrial | 0 | | | 0 | | | 96 | | | 3 | | | 0 | | | 3 | | | 0 | |
| Transportation | 0 | | | 18 | | | 0 | | | 10 | | | 0 | | | 10 | | | 0 | |
Other(c) | 0 | | | 3 | | | 16 | | | 5 | | | 0 | | | 5 | | | 0 | |
Total rate-regulated natural gas revenues(d) | $ | 0 | | | $ | 359 | | | $ | 509 | | | $ | 116 | | | $ | 0 | | | $ | 116 | | | $ | 0 | |
| Total rate-regulated revenues from contracts with customers | $ | 4,540 | | | $ | 2,293 | | | $ | 2,290 | | | $ | 3,567 | | | $ | 1,629 | | | $ | 968 | | | $ | 972 | |
| | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (51) | | | $ | 10 | | | $ | (10) | | | $ | (15) | | | $ | 20 | | | $ | (15) | | | $ | (20) | |
Other rate-regulated electric revenues(e) | 10 | | | 3 | | | 3 | | | 2 | | | 1 | | | 1 | | | 0 | |
Other rate-regulated natural gas revenues(e) | 0 | | | 0 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | |
| Total other revenues | $ | (41) | | | $ | 13 | | | $ | (6) | | | $ | (13) | | | $ | 21 | | | $ | (14) | | | $ | (20) | |
| Total rate-regulated revenues for reportable segments | $ | 4,499 | | | $ | 2,306 | | | $ | 2,284 | | | $ | 3,554 | | | $ | 1,650 | | | $ | 954 | | | $ | 952 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 4 — Segment Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 2,221 | | | $ | 1,231 | | | $ | 1,019 | | | $ | 1,816 | | | $ | 792 | | | $ | 499 | | | $ | 525 | |
| Small commercial & industrial | 1,103 | | | 304 | | | 193 | | | 387 | | | 114 | | | 141 | | | 132 | |
| Large commercial & industrial | 399 | | | 163 | | | 335 | | | 843 | | | 633 | | | 75 | | | 135 | |
| Public authorities & electric railroads | 35 | | | 23 | | | 20 | | | 47 | | | 27 | | | 10 | | | 10 | |
Other(a) | 660 | | | 186 | | | 242 | | | 481 | | | 166 | | | 151 | | | 164 | |
Total rate-regulated electric revenues(b) | $ | 4,418 | | | $ | 1,907 | | | $ | 1,809 | | | $ | 3,574 | | | $ | 1,732 | | | $ | 876 | | | $ | 966 | |
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | 0 | | | $ | 285 | | | $ | 327 | | | $ | 64 | | | $ | 0 | | | $ | 64 | | | $ | 0 | |
| Small commercial & industrial | 0 | | | 122 | | | 55 | | | 30 | | | 0 | | | 30 | | | 0 | |
| Large commercial & industrial | 0 | | | 1 | | | 93 | | | 4 | | | 0 | | | 4 | | | 0 | |
| Transportation | 0 | | | 18 | | | 0 | | | 11 | | | 0 | | | 11 | | | 0 | |
Other(c) | 0 | | | 5 | | | 19 | | | 6 | | | 0 | | | 6 | | | 0 | |
Total rate-regulated natural gas revenues(d) | $ | 0 | | | $ | 431 | | | $ | 494 | | | $ | 115 | | | $ | 0 | | | $ | 115 | | | $ | 0 | |
| Total rate-regulated revenues from contracts with customers | $ | 4,418 | | | $ | 2,338 | | | $ | 2,303 | | | $ | 3,689 | | | $ | 1,732 | | | $ | 991 | | | $ | 966 | |
| | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (98) | | | $ | (16) | | | $ | 11 | | | $ | 4 | | | $ | 10 | | | $ | (6) | | | $ | 0 | |
Other rate-regulated electric revenues(e) | 22 | | | 10 | | | 10 | | | 7 | | | 6 | | | 1 | | | 0 | |
Other rate-regulated natural gas revenues(e) | 0 | | | 1 | | | 3 | | | 0 | | | 0 | | | 1 | | | 0 | |
| | | | | | | | | | | | | |
| Total other revenues | $ | (76) | | | $ | (5) | | | $ | 24 | | | $ | 11 | | | $ | 16 | | | $ | (4) | | | $ | 0 | |
| Total rate-regulated revenues for reportable segments | $ | 4,342 | | | $ | 2,333 | | | $ | 2,327 | | | $ | 3,700 | | | $ | 1,748 | | | $ | 987 | | | $ | 966 | |
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $31 million, $6 million, $9 million, $13 million, $6 million, $7 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, respectively, in 2020 and $13 million, $4 million, $5 million, $11 million, $5 million, $5 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, respectively, in 2019.
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates of $1 million and $7 million at PECO and BGE, respectively, in 2020 and less than $1 million and $13 million at PECO and BGE, respectively, in 2019.
(e)Includes late payment charge revenues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Accounts Receivable
5. Accounts Receivable (All Registrants)
Allowance for Credit Losses on Accounts Receivable (All Registrants)
The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2020 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of June 30, 2020 | $ | 261 | | | $ | 33 | | | $ | 72 | | | $ | 71 | | | $ | 23 | | | $ | 62 | | | $ | 24 | | | $ | 18 | | | $ | 20 | |
Plus: Current Period Provision for Expected Credit Losses(a) | 114 | | | 1 | | | 37 | | | 27 | | | 14 | | | 35 | | | 11 | | | 7 | | | 17 | |
Less: Write-offs, net of recoveries(b) | 17 | | | 1 | | | 4 | | | 2 | | | 2 | | | 8 | | | 0 | | | 3 | | | 5 | |
| | | | | | | | | | | | | | | | | |
| Balance as of September 30, 2020 | $ | 358 | | | $ | 33 | | | $ | 105 | | | $ | 96 | | | $ | 35 | | | $ | 89 | | | $ | 35 | | | $ | 22 | | | $ | 32 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 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) | 222 | | | 13 | | | 62 | | | 56 | | | 28 | | | 63 | | | 24 | | | 14 | | | 25 | |
Less: Write-offs, net of recoveries(b) | 51 | | | 4 | | | 16 | | | 15 | | | 5 | | | 11 | | | 2 | | | 3 | | | 6 | |
Less: Sale of customer accounts receivable(c) | 56 | | | 56 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Balance as of September 30, 2020 | $ | 358 | | | $ | 33 | | | $ | 105 | | | $ | 96 | | | $ | 35 | | | $ | 89 | | | $ | 35 | | | $ | 22 | | | $ | 32 | |
_________
(a)For the Utility Registrants, the increase is primarily as a result of increased aging of receivables, the temporary suspension of customer disconnections for non-payment, temporary cessation of new late payment fees, and reconnection of service to customers previously disconnected due to COVID-19.
(b)Recoveries were not material to the Registrants.
(c)See below for additional information on the sale of customer accounts receivable at Generation in the second quarter of 2020.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Accounts Receivable
The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2020 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Balance as of June 30, 2020 | $ | 61 | | | $ | 0 | | | $ | 22 | | | $ | 7 | | | $ | 6 | | | $ | 26 | | | $ | 11 | | | $ | 7 | | | $ | 8 | |
| Plus: Current Period Provision for Expected Credit Losses | 15 | | | 0 | | | 5 | | | 1 | | | 3 | | | 6 | | | 2 | | | 1 | | | 3 | |
Less: Write-offs, net of recoveries(a) | 1 | | | 0 | | | 0 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Balance as of September 30, 2020 | $ | 75 | | | $ | 0 | | | $ | 27 | | | $ | 7 | | | $ | 9 | | | $ | 32 | | | $ | 13 | | | $ | 8 | | | $ | 11 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| 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 | 36 | | | 0 | | | 9 | | | 3 | | | 7 | | | 17 | | | 6 | | | 4 | | | 7 | |
Less: Write-offs, net of recoveries(a) | 9 | | | 0 | | | 2 | | | 3 | | | 3 | | | 1 | | | 0 | | | 0 | | | 1 | |
| Balance as of September 30, 2020 | $ | 75 | | | $ | 0 | | | $ | 27 | | | $ | 7 | | | $ | 9 | | | $ | 32 | | | $ | 13 | | | $ | 8 | | | $ | 11 | |
_________
(a)Recoveries were not material to the Registrants.
Unbilled Customer Revenue (All Registrants)
The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unbilled customer revenues(a) |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| September 30, 2020 | $ | 672 | | | $ | 139 | | | $ | 193 | | | $ | 98 | | | $ | 115 | | | $ | 127 | | | $ | 72 | | | $ | 37 | | | $ | 18 | |
| 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 mutual consent of the parties 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 subordinated 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 5 — Accounts Receivable
The following table summarizes the impact of the sale of certain receivables:
| | | | | |
| As of September 30, 2020 |
Derecognized receivables transferred at fair value(a) | $ | 1,232 | |
| Cash proceeds received | 500 | |
| DPP | 732 | |
_________
(a)Includes additional customer accounts receivable sold into the Facility of $4,515 million since the start of the financing agreement.
| | | | | | | | | | | |
| Three months ended September 30, 2020 | | Nine months ended September 30, 2020 |
Loss on sale of receivables(a) | $ | 8 | | | $ | 23 | |
_________
(a)Reflected in Operating and maintenance expense on Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income.
| | | | | |
| Nine months ended September 30, 2020 |
| Proceeds from new transfers | $ | 1,889 | |
| Cash collections received on DPP | 2,518 | |
| Cash collections reinvested in the Facility | 4,407 | |
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.
Generation reflected the cash proceeds received upon sale in Net cash provided by operating activities in the Consolidated Statements of Cash Flows. The collection and reinvestment of DPP is recognized in Net cash provided by investing activities of the Consolidated Statements of Cash Flows.
See Note 13 — Fair Value of Financial Assets and Liabilities and Note 16 — Variable Interest Entities for additional information.
Other Purchases and Sales of Customer and Other Accounts Receivables (All Registrants)
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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Total Receivables Purchased | $ | 2,698 | | | $ | 0 | | | $ | 865 | | | $ | 786 | | | $ | 508 | | | $ | 787 | | | $ | 484 | | | $ | 160 | | | $ | 143 | |
| Total Receivables Sold | 542 | | | 790 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Related Party Transactions: | | | | | | | | | | | | | | | | | |
| Receivables purchased from Generation | — | | | — | | | 34 | | | 67 | | | 75 | | | 72 | | | 51 | | | 13 | | | 8 | |
| Receivables sold to the Utility Registrants | — | | | 248 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Early Plant Retirements
6. 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 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 TMI nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. 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.
Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program, and the New 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 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 addition, FERC’s December 19, 2019 order on the MOPR in PJM may undermine the continued effectiveness of the Illinois ZES and the New Jersey ZEC program unless Illinois and New Jersey implement an FRR mechanism under which the Generation plants in these states would be removed from PJM’s capacity auction. See Note 2 — Regulatory Matters for additional information on the New Jersey ZEC program, New York CES, and FERC's December 19, 2019 order and Note 3 — Regulatory Matters of the 2019 Form 10-K for additional information on the Illinois ZES.
In Pennsylvania, the TMI 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 low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Generation announced that it would permanently cease generation operations at TMI. On September 20, 2019, Generation permanently ceased generation operations at TMI.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Early Plant Retirements
Generation’s Dresden, Byron, and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, 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 in the third quarter of 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 provisionof 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 7 - Nuclear Decommissioning for Conowingo assumesadditional information on changes to the nuclear decommissioning ARO balance and Note 8 — 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) | | Three and Nine Months Ended September 30, 2020(a) | | Three Months Ended September 30, 2019(b) | | Nine Months Ended September 30, 2019(b) |
| Depreciation and amortization | | | | | | |
Accelerated depreciation(c) | | $ | 254 | | | $ | 71 | | | $ | 216 | |
| Accelerated nuclear fuel amortization | | 14 | | | 3 | | | 13 | |
| Operating and maintenance | | | | | | |
| One-time charges | | 220 | | | 0 | | | 0 | |
Other charges(d) | | 34 | | | 39 | | | (44) | |
Contractual offset(e) | | (129) | | | 0 | | | 0 | |
| Total | | $ | 393 | | | $ | 113 | | | $ | 185 | |
| | | | | | |
_________
(a)Reflects expense for Byron and Dresden.
(b)Reflects expense for TMI.
(c)Includes the accelerated depreciation of plant assets including any ARC.
(d)For Dresden, reflects the net impacts associated with the remeasurement of the ARO. See Note 7 - Nuclear Decommissioning for additional information. For TMI, primarily reflects the net impacts associated with the remeasurement of the ARO. See Note 9 - Asset Retirement Obligations of the 2019 Form 10-K for additional information.
(e)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. 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 9 - Asset Retirement Obligations of the Exelon 2019 Form 10-K for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 6 — Early Plant Retirements
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. In the third quarter of 2020, Exelon and Generation recorded estimated 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 September 30, 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 | | | | | | $ | 82 | | | $ | 107 | | | $ | 189 | |
| Nuclear fuel inventory, net | | | | | | 147 | | | 218 | | | 365 | |
| Completed plant, net | | | | | | 1,403 | | | 1,571 | | | 2,974 | |
| Construction work in progress | | | | | | 18 | | | 23 | | | 41 | |
| Liability Balances | | | | | | | | | | |
| Asset retirement obligation | | | | | | (570) | | | (926) | | | (1,496) | |
| | | | | | | | | | |
| 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
In March 2018, Generation notified ISO-NE of its plans to early retire, among other assets, the Mystic Generating Station's units 8 and 9 (Mystic 8 and 9) absent regulatory reforms to 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 - May 31, 2024. The agreement was approved by the FERC license.in December 2018.
On June 10, 2020, Generation filed a complaint with FERC against ISO-NE stating that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic 8 and 9 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 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 in May 2024. See Note 2 — Regulatory Matters for additional discussion of Mystic’s cost of service agreement.
As a result of the decision to early retire Mystic 8 and 9, Exelon and Generation recognized $43 million of one-time charges related to an expected long-term maintenance contract termination and 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 Mystic 8 and 9 primarily related to accelerated depreciation of plant assets. Exelon and Generation recorded incremental Depreciation and amortization expense of $6 million in the third quarter of 2020. See Note 8 — Asset Impairments for impairment assessment considerations of the New England Asset Group.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 7 — Nuclear Decommissioning
7. Nuclear Decommissioning (Exelon and Generation)
Nuclear Decommissioning Asset Retirement Obligations
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.
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 December 31, 2019 to September 30, 2020:
| | | | | |
Nuclear decommissioning ARO at December 31, 2019 (a) | $ | 10,504 | |
| Accretion expense | 367 | |
| Net increase due to changes in, and timing of, estimated future cash flows | 806 | |
| Costs incurred related to decommissioning plants | (59) | |
Nuclear decommissioning ARO at September 30, 2020 (a) | $ | 11,618 | |
_________
(a)Includes $93 million and $112 million as the current portion of the ARO at September 30, 2020 and December 31, 2019, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.
During the nine months ended September 30, 2020, the net $806 million increase in the ARO for the changes in the amounts and timing of estimated decommissioning cash flows 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 6 — Early Plant Retirements for additional information.
NDT Funds
Exelon and Generation had NDT funds totaling $13,547 million and $13,353 million at September 30, 2020 and December 31, 2019, respectively. The NDT funds also include $115 million and $163 million for the current portion of the NDT funds at September 30, 2020 and December 31, 2019, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 17 — Supplemental Financial Information for additional information on activities of the NDT funds.
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.
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 7 — Nuclear Decommissioning
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. See Note 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for information regarding the amount collected from PECO ratepayers for decommissioning cost.
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 impact of the announced early retirement 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.
8. 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.
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. 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 2 — Variable Interest Entities for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 7 — Asset Impairments
Antelope Valley Solar FacilityOther Generation
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells allIn March 2018, Generation notified ISO-NE of its outputplans to PG&E throughearly retire, among other assets, the Mystic Generating Station's units 8 and 9 (Mystic 8 and 9) absent regulatory reforms to 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 PPA.cost of service agreement with these two units for the period between June 1, 2022 - May 31, 2024. The agreement was approved by the FERC in December 2018.
On June 10, 2020, Generation filed a complaint with FERC against ISO-NE stating that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic 8 and 9 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 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 September 30, 2019, Generation had approximately $730 millionthe cost of net long-lived assets related to Antelope Valley. service commitment in May 2024. See Note 2 — Regulatory Matters for additional discussion of Mystic’s cost of service agreement.
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 flowsdecision to early retire Mystic 8 and no impairment charge was recorded. Significant 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’s net long-lived assets, which could be material.
Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,930 million of additional net long-lived assets as of September 30, 2019. EGR IV is a wholly owned indirect subsidiary of9, Exelon and Generation recognized $43 million of one-time charges related to an expected long-term maintenance contract termination and includes Generation's interest in EGRPmaterials and supplies inventory reserve adjustments, among other projects with non-controlling interests. To date,items. In addition, there have been no indicatorsare annual financial impacts stemming from shortening the expected economic useful life of Mystic 8 and 9 primarily related to suggest that the carrying amountaccelerated depreciation of other net long-lived assets of EGR IV may not be recoverable.
Generation will continue to monitor the bankruptcy proceedings for any changes in circumstances that may indicate the carrying amount of the net long-lived assets of Antelope Valley or other long-lived assets of EGR IV may not be recoverable.
See Note 11 - Debt and Credit Agreements for additional information on the PG&E bankruptcy.
8. Early Plant Retirements (Exelon and Generation)
plant assets. Exelon and Generation continuously evaluate factors that affectrecorded incremental Depreciation and amortization expense of $6 million in the current and expected economic valuethird quarter 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 compensated2020. See Note 8 — Asset Impairments for 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 Island nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. 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.
Assuming the continued effectivenessimpairment assessment considerations of the Illinois ZES, New Jersey ZEC program and the New 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 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. See Note 6 — Regulatory Matters for additional information on the Illinois ZES, New Jersey ZEC program and New York CES.England Asset Group.
In Pennsylvania, the TMI 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 low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Generation announced that it would permanently cease generation operations at TMI. On September 20, 2019, Generation permanently ceased generation operations at TMI.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 87 — Nuclear Decommissioning
7. Nuclear Decommissioning (Exelon and Generation)
Nuclear Decommissioning Asset Retirement Obligations
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.
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 December 31, 2019 to September 30, 2020:
| | | | | |
Nuclear decommissioning ARO at December 31, 2019 (a) | $ | 10,504 | |
| Accretion expense | 367 | |
| Net increase due to changes in, and timing of, estimated future cash flows | 806 | |
| Costs incurred related to decommissioning plants | (59) | |
Nuclear decommissioning ARO at September 30, 2020 (a) | $ | 11,618 | |
_________
(a)Includes $93 million and $112 million as the current portion of the ARO at September 30, 2020 and December 31, 2019, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.
During the nine months ended September 30, 2020, the net $806 million increase in the ARO for the changes in the amounts and timing of estimated decommissioning cash flows 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 6 — Early Plant Retirements
for additional information.
On February 2, 2018,Exelon and Generation announcedhad NDT funds totaling $13,547 million and $13,353 million at September 30, 2020 and December 31, 2019, respectively. The NDT funds also include $115 million and $163 million for the current portion of the NDT funds at September 30, 2020 and December 31, 2019, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 17 — Supplemental Financial Information for additional information on activities of the NDT funds.
NRC Minimum Funding Requirements
NRC regulations require that it would permanently cease generation operations atlicensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the Oyster Creek nuclear plantfacility at the end of its current operating cyclelife.
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 permanently ceased generation operations on September 17, 2018.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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 137 — Nuclear Decommissioning
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. See Note 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for information regarding the amount collected from PECO ratepayers for decommissioning cost.
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 impact of the announced early retirement 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.
8. 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 nuclear decommissioning ARO balance.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 total impact forfair value analysis is primarily based on the threeincome approach using significant unobservable inputs (Level 3) including revenue and nine months ended September 30, 2019generation forecasts, projected capital and 2018 are summarizedmaintenance expenditures, and discount rates. A variation in the table below.
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Income statement expense (pre-tax) | | 2019 | | 2018 | | 2019 | | 2018 |
Depreciation and amortization(a) | | | | | | | | |
| Accelerated depreciation | | $ | 71 |
| | $ | 152 |
| | $ | 216 |
| | $ | 441 |
|
| Accelerated nuclear fuel amortization | | 3 |
| | 18 |
| | 13 |
| | 52 |
|
Operating and maintenance(b) | | 39 |
| | 4 |
| | (44 | ) | | 32 |
|
| Total | | $ | 113 |
| | $ | 174 |
| | $ | 185 |
| | $ | 525 |
|
_________
| |
(a) | Reflects incremental accelerated depreciation and amortization for TMI for the three and nine months ended September 30, 2019. Reflects incremental accelerated depreciation for TMI and Oyster Creek for the three and nine months ended September 30, 2018. The Oyster Creek amounts are from February 2, 2018 through September 17, 2018. The TMI amounts are through September 20, 2019. |
| |
(b) | In 2019, primarily reflects the net impacts associated with the remeasurements of the TMI ARO in the first and third quarters. See Note 13 — Nuclear Decommissioning for additional information on the first quarter 2019 TMI ARO update. In 2018, primarily reflects materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments associated with the early retirement decisions for TMI and Oyster Creek. Excludes the charges in the third quarter of 2018 and second quarter of 2019 to Operating and maintenance expense for the ARO remeasurement due to the sale of Oyster Creek. See Note 3 — Mergers, Acquisitions and Dispositions for additional information. |
Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, whichassumptions used could lead to a different conclusion regarding the recoverability of an early retirement,asset or asset group and, thus, could potentially result in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amountsmaterial future impairments 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.Registrant's long-lived assets.
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 on June 1, 2022, atto properly value reliability and regional fuel security. Thereafter, ISO-NE identified Mystic 8 and 9 as being needed to ensure fuel security for the end of the then-current capacity commitment for Mystic Units 7region and 8. Mystic Unit 9 was then committed through May 2021.
On May 16, 2018, Generation madeentered into a filing with FERC to establish cost-of-service compensation and terms and conditionscost of service for Mystic Units 8 and 9agreement with these two units for the period between June 1, 2022 - May 31, 2024. The agreement was approved by the FERC in December 2018.
On December 20, 2018,June 10, 2020, Generation filed a complaint with FERC against ISO-NE stating that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic 8 and 9 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 8 and 9 should have been filed with FERC for approval. On August 17, 2020, FERC issued an order acceptingdenying 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 agreement reflectingcommitment in May 2024. See Note 2 — Regulatory Matters for additional discussion of Mystic’s cost of service agreement.
As a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portionresult of the costs associated with the Everett Marine Terminal. Those adjustments were reflected in a compliance filing filed March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. Initial briefs in the ROE proceeding were filed on April 19, 2019 and reply briefs were filed on July 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, which does not alter Generation's commitmentdecision to participate in the Forward Capacity Auction for the 2022-2023 capacity commitment period. On June 10, 2019, ISO-NE announced that it has determined thatearly retire Mystic 8 and 9, Exelon and Generation recognized $43 million of one-time charges related to an expected long-term maintenance contract termination and materials and supplies inventory reserve adjustments, among other items. In addition, there are neededannual financial impacts stemming from shortening the expected economic useful life of Mystic 8 and 9 primarily related to accelerated depreciation of plant assets. Exelon and Generation recorded incremental Depreciation and amortization expense of $6 million in the third quarter of 2020. See Note 8 — Asset Impairments for fuel security forimpairment assessment considerations of the 2023-2024 capacity commitment period.New England Asset Group.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 87 — Early Plant RetirementsNuclear Decommissioning
On March 25, 2019, ISO-NE filedNuclear Decommissioning Asset Retirement Obligations
Generation has a legal obligation to decommission its nuclear power plants following the Inventoried Energy Program,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.
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 intended to provide an interim fuel security program pending conclusionrecorded as decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of the stakeholder process to develop a long-term, market-based solution to address fuel security. Exelon filed comments on the Inventoried Energy Program proposal on April 15, 2019. On May 8, 2019, FERC issued a deficiency letter to ISO-NE seeking additional information on the Inventoried Energy Program proposal,Operations and ISO-NE filed a response on June 6, 2019. On August 5, 2019, FERC allowed the Inventoried Energy Program to take effect by operation of law. Several parties have filed requests for rehearing. FERC ordered ISO-NE to file long-term, market-based fuel security rules by October 15, 2019. On August 30, 2019, FERC granted an extension of time to file the long-term, market-based fuel security rules to April 15, 2020.Comprehensive Income.
The following table provides a rollforward of the balance sheet amounts as ofnuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2019 to September 30, 2019 for Exelon's2020:
| | | | | |
Nuclear decommissioning ARO at December 31, 2019 (a) | $ | 10,504 | |
| Accretion expense | 367 | |
| Net increase due to changes in, and timing of, estimated future cash flows | 806 | |
| Costs incurred related to decommissioning plants | (59) | |
Nuclear decommissioning ARO at September 30, 2020 (a) | $ | 11,618 | |
_________
(a)Includes $93 million and Generation’s significant assets and liabilities associated with$112 million as the Mystic Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by the failure to adopt long-term solutions for reliability and fuel security.
|
| | | | |
| | | September 30, 2019 |
| Asset Balances | | |
| Materials and supplies inventory | | $ | 31 |
|
| Fuel inventory | | 5 |
|
| Completed plant, net | | 889 |
|
| Construction work in progress | | 7 |
|
| Liability Balances | | |
| Asset retirement obligation | | (2 | ) |
9. 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 ascurrent portion 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.
Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 11 — Fair Value of Financial Assets and Liabilities of the Exelon 2018 Form 10-K, unless otherwise noted below.
Fair Value of Financial Liabilities RecordedARO 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 September 30, 20192020 and December 31, 2018. The Registrants have no financial2019, respectively, which is included in Other current liabilities classifiedin Exelon’s and Generation’s Consolidated Balance Sheets.
During the nine months ended September 30, 2020, the net $806 million increase in the ARO for the changes in the amounts and timing of estimated decommissioning cash flows was driven by updates to Byron and Dresden reflecting changes in assumed retirement dates and assumed methods of decommissioning as Level 1.
The carrying amountsa result of the Registrants’ short-term liabilities as presented on theirannouncement to early retire these plants in 2021. Refer to Note 6 — Early Plant Retirements for additional information.
NDT Funds
Exelon and Generation had NDT funds totaling $13,547 million and $13,353 million at September 30, 2020 and December 31, 2019, respectively. The NDT funds also include $115 million and $163 million for the current portion of the NDT funds at September 30, 2020 and December 31, 2019, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets are representative of their fair value (Level 2) becauseSheets. See Note 17 — Supplemental Financial Information for additional information on activities of the short-term natureNDT funds.
NRC Minimum Funding Requirements
NRC regulations require that licensees of these instruments.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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 7 — Nuclear Decommissioning
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. See Note 9 — Fair ValueAsset Retirement Obligations of Financial Assetsthe Exelon 2019 Form 10-K for information regarding the amount collected from PECO ratepayers for decommissioning cost.
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 Liabilities
will include the impact of the announced early retirement 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.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | September 30, 2019 | | December 31, 2018 |
| | | 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 | | $ | 36,304 |
| | $ | 38,056 |
| | $ | 2,541 |
| | $ | 40,597 |
| | $ | 35,424 |
| | $ | 33,711 |
| | $ | 2,158 |
| | $ | 35,869 |
|
| Generation | | 8,613 |
| | 7,962 |
| | 1,398 |
| | 9,360 |
| | 8,793 |
| | 7,467 |
| | 1,443 |
| | 8,910 |
|
| ComEd | | 8,196 |
| | 9,622 |
| | — |
| | 9,622 |
| | 8,101 |
| | 8,390 |
| | — |
| | 8,390 |
|
| PECO | | 3,404 |
| | 3,891 |
| | 50 |
| | 3,941 |
| | 3,084 |
| | 3,157 |
| | 50 |
| | 3,207 |
|
| BGE | | 3,270 |
| | 3,678 |
| | — |
| | 3,678 |
| | 2,876 |
| | 2,950 |
| | — |
| | 2,950 |
|
| PHI | | 6,494 |
| | 5,993 |
| | 1,093 |
| | 7,086 |
| | 6,259 |
| | 5,436 |
| | 665 |
| | 6,101 |
|
| Pepco | | 2,860 |
| | 3,249 |
| | 395 |
| | 3,644 |
| | 2,719 |
| | 2,901 |
| | 196 |
| | 3,097 |
|
| DPL | | 1,495 |
| | 1,437 |
| | 232 |
| | 1,669 |
| | 1,494 |
| | 1,303 |
| | 193 |
| | 1,496 |
|
| ACE | | 1,324 |
| | 1,034 |
| | 466 |
| | 1,500 |
| | 1,188 |
| | 987 |
| | 275 |
| | 1,262 |
|
Long-Term Debt to Financing Trusts(a)
|
| Exelon | | $ | 390 |
| | $ | — |
| | $ | 426 |
| | $ | 426 |
| | $ | 390 |
| | $ | — |
| | $ | 400 |
| | $ | 400 |
|
| ComEd | | 205 |
| | — |
| | 223 |
| | 223 |
| | 205 |
| | — |
| | 209 |
| | 209 |
|
| PECO | | 184 |
| | — |
| | 203 |
| | 203 |
| | 184 |
| | — |
| | 191 |
| | 191 |
|
| SNF Obligation |
| Exelon | | $ | 1,193 |
| | $ | 1,017 |
| | $ | — |
| | $ | 1,017 |
| | $ | 1,171 |
| | $ | 949 |
| | $ | — |
| | $ | 949 |
|
| Generation | | 1,193 |
| | 1,017 |
| | — |
| | 1,017 |
| | 1,171 |
| | 949 |
| | — |
| | 949 |
|
____ | |
(a) | Includes unamortized debt issuance costs which are not fair valued. |
Recurring Fair Value Measurements8. Asset Impairments (Exelon and Generation)
The following tables presentRegistrants evaluate the carrying value of long-lived assets and liabilities measured and recorded ator 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 Registrants' Consolidated Balance Sheetsassumptions 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 no 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 12 - 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 second quarter of 2018, Generation completed a recurring basiscomprehensive review of the estimated undiscounted future cash flows of the New England asset group and their level withinno 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 hierarchy as of September 30, 2019the 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 December 31, 2018:
Exelonmaintenance expense in Exelon’s and GenerationGeneration’s
92
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation |
| As of September 30, 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) | $ | 1,719 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,719 |
| | $ | 896 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 896 |
|
| NDT fund investments | | | | | | | | |
| | | | | | | | | |
|
Cash equivalents(b) | 315 |
| | 78 |
| | — |
| | — |
| | 393 |
| | 315 |
| | 78 |
| | — |
| | — |
| | 393 |
|
| Equities | 3,121 |
| | 1,727 |
| | — |
|
| 1,314 |
| | 6,162 |
| | 3,121 |
| | 1,727 |
| | — |
|
| 1,314 |
| | 6,162 |
|
| Fixed income | | | | | | | | | | | | | | | | | | | |
| Corporate debt | — |
| | 1,473 |
| | 259 |
| | — |
| | 1,732 |
| | — |
| | 1,473 |
| | 259 |
| | — |
| | 1,732 |
|
| U.S. Treasury and agencies | 1,777 |
| | 152 |
| | — |
| | — |
| | 1,929 |
| | 1,777 |
| | 152 |
| | — |
| | — |
| | 1,929 |
|
| Foreign governments | — |
| | 56 |
| | — |
| | — |
| | 56 |
| | — |
| | 56 |
| | — |
| | — |
| | 56 |
|
| State and municipal debt | — |
| | 85 |
| | — |
| | — |
| | 85 |
| | — |
| | 85 |
| | — |
| | — |
| | 85 |
|
Other(c) | — |
| | 23 |
| | — |
| | 979 |
| | 1,002 |
| | — |
| | 23 |
| | — |
| | 979 |
| | 1,002 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 98 — Fair ValueAsset Impairments
Consolidated Statements of Financial AssetsOperations and Liabilities
Comprehensive Income. See Note 6 - 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 no impairment charge was required.
We 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 6 - 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. 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 16 — Variable Interest Entities for additional information.
9. Income Taxes (All Registrants)
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2020(a) | |
| | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO(b) | | BGE | | PHI(c) | | Pepco | | DPL | | ACE(c) | |
| 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 | 12.3 | | (10.3) | | 8.1 | | (6.2) | | 5.1 | | 5.5 | | 4.6 | | 6.6 | | 6.9 | |
| Qualified NDT fund income | 13.2 | | 47.4 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| | | | | | | | | | | | | | | | | | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.4) | | (4.5) | | (0.2) | | 0 | | (0.1) | | (0.2) | | (0.1) | | (0.2) | | (0.3) | |
| Plant basis differences | (4.3) | | 0 | | (0.6) | | (23.3) | | (1.2) | | (1.5) | | (2.1) | | (0.4) | | (1.3) | |
| Production tax credits and other credits | (3.0) | | (9.2) | | (0.4) | | 0 | | (0.8) | | (0.5) | | (0.5) | | (0.5) | | (0.4) | |
| Noncontrolling interests | 0.8 | | 2.9 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Excess deferred tax amortization | (10.1) | | 0 | | (5.6) | | (3.8) | | (10.6) | | (24.9) | | (20.0) | | (23.6) | | (36.8) | |
| Tax settlements | (0.2) | | (0.7) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Other | (0.8) | | (0.9) | | 1.1 | | (0.8) | | (0.3) | | 0.1 | | (0.4) | | 0.7 | | 0.6 | |
| Effective income tax rate | 27.5% | | 45.7% | | 23.4% | | (13.1)% | | 13.1% | | (0.5)% | | 2.5% | | 3.6% | | (10.3)% | |
93
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation |
| As of September 30, 2019 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
| Fixed income subtotal | 1,777 |
|
| 1,789 |
|
| 259 |
| | 979 |
|
| 4,804 |
|
| 1,777 |
|
| 1,789 |
|
| 259 |
| | 979 |
|
| 4,804 |
|
| Middle market lending | — |
| | — |
| | 255 |
| | 445 |
| | 700 |
| | — |
| | — |
| | 255 |
| | 445 |
| | 700 |
|
| Private equity | — |
| | — |
| | — |
| | 398 |
| | 398 |
| | — |
| | — |
| | — |
| | 398 |
| | 398 |
|
| Real estate | — |
| | — |
| | — |
| | 581 |
| | 581 |
| | — |
| | — |
| | — |
| | 581 |
| | 581 |
|
NDT fund investments subtotal(d) | 5,213 |
|
| 3,594 |
|
| 514 |
| | 3,717 |
|
| 13,038 |
|
| 5,213 |
|
| 3,594 |
|
| 514 |
| | 3,717 |
|
| 13,038 |
|
| Rabbi trust investments | | | | | | | | |
| | | | | | | | | |
|
| Cash equivalents | 49 |
| | — |
| | — |
| | — |
| | 49 |
| | 4 |
| | — |
| | — |
| | — |
| | 4 |
|
| Mutual funds | 77 |
| | — |
| | — |
| | — |
| | 77 |
| | 24 |
| | — |
| | — |
| | — |
| | 24 |
|
| Fixed income | — |
| | 13 |
| | — |
| | — |
| | 13 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Life insurance contracts | — |
| | 76 |
| | 40 |
| | — |
| | 116 |
| | — |
| | 24 |
| | — |
| | — |
| | 24 |
|
| Rabbi trust investments subtotal | 126 |
|
| 89 |
|
| 40 |
| | — |
|
| 255 |
|
| 28 |
|
| 24 |
|
| — |
| | — |
|
| 52 |
|
| Commodity derivative assets | | | | | | | | | | | | | | | | | | | |
| Economic hedges | 533 |
| | 1,488 |
| | 1,817 |
| | — |
| | 3,838 |
| | 533 |
| | 1,488 |
| | 1,817 |
| | — |
| | 3,838 |
|
| Proprietary trading | — |
| | 54 |
| | 156 |
| | — |
| | 210 |
| | — |
| | 54 |
| | 156 |
| | — |
| | 210 |
|
Effect of netting and allocation of collateral(e)(f) | (677 | ) | | (1,261 | ) | | (1,025 | ) | | — |
| | (2,963 | ) | | (677 | ) | | (1,261 | ) | | (1,025 | ) | | — |
| | (2,963 | ) |
| Commodity derivative assets subtotal | (144 | ) |
| 281 |
|
| 948 |
| | — |
|
| 1,085 |
|
| (144 | ) |
| 281 |
|
| 948 |
| | — |
|
| 1,085 |
|
| Total assets | 6,914 |
|
| 3,964 |
|
| 1,502 |
|
| 3,717 |
|
| 16,097 |
|
| 5,993 |
|
| 3,899 |
|
| 1,462 |
|
| 3,717 |
|
| 15,071 |
|
| Liabilities | | | | | | | | | | | | | | | | | | | |
| Commodity derivative liabilities | | | | | | | | | | | | | | | | | | | |
| Economic hedges | (773 | ) | | (1,695 | ) | | (1,686 | ) | | — |
| | (4,154 | ) | | (773 | ) | | (1,695 | ) | | (1,406 | ) | | — |
| | (3,874 | ) |
| Proprietary trading | — |
| | (59 | ) | | (89 | ) | | — |
| | (148 | ) | | — |
| | (59 | ) | | (89 | ) | | — |
| | (148 | ) |
Effect of netting and allocation of collateral(e)(f) | 770 |
| | 1,585 |
| | 1,329 |
| | — |
| | 3,684 |
| | 770 |
| | 1,585 |
| | 1,329 |
| | — |
| | 3,684 |
|
| Commodity derivative liabilities subtotal | (3 | ) | | (169 | ) | | (446 | ) | | — |
| | (618 | ) | | (3 | ) | | (169 | ) | | (166 | ) | | — |
| | (338 | ) |
| Deferred compensation obligation | — |
| | (140 | ) | | — |
| | — |
| | (140 | ) | | — |
| | (37 | ) | | — |
| | — |
| | (37 | ) |
| Total liabilities | (3 | ) |
| (309 | ) |
| (446 | ) | | — |
|
| (758 | ) |
| (3 | ) |
| (206 | ) |
| (166 | ) | | — |
|
| (375 | ) |
| Total net assets | $ | 6,911 |
|
| $ | 3,655 |
|
| $ | 1,056 |
| | $ | 3,717 |
|
| $ | 15,339 |
|
| $ | 5,990 |
|
| $ | 3,693 |
|
| $ | 1,296 |
| | $ | 3,717 |
|
| $ | 14,696 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Fair Value of Financial Assets and LiabilitiesIncome Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 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 | 6.4 | | 5.2 | | 8.1 | | (0.3) | | 6.3 | | 4.8 | | 1.9 | | 6.6 | | 6.9 |
| Qualified NDT fund income | 3.2 | | 7.1 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Amortization of investment tax credit, including deferred taxes on basis difference | (4.1) | | (8.9) | | (0.2) | | 0 | | (0.1) | | (0.2) | | (0.1) | | (0.2) | | (0.3) |
| Plant basis differences | (1.7) | | 0 | | (1.0) | | (7.5) | | (1.1) | | (1.8) | | (2.6) | | (0.6) | | (1.9) |
| Production tax credits and other credits | (1.2) | | (2.7) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Noncontrolling interests | (2.2) | | (4.8) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Excess deferred tax amortization | (6.5) | | 0 | | (9.9) | | (3.6) | | (8.0) | | (17.7) | | (16.3) | | (13.5) | | (23.3) |
| Other | 0.7 | | 0.5 | | 0.4 | | (0.5) | | (0.2) | | 0.8 | | 1.0 | | (0.1) | | 0.7 |
| Effective income tax rate | 15.6% | | 17.4% | | 18.4% | | 9.1% | | 17.9% | | 6.9% | | 4.9% | | 13.2% | | 3.1% |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020(a) | |
| | | | | | | | | | | | | | | | | | |
| Exelon | | Generation(d) | | ComEd(e) | | PECO(b) | | BGE(c) | | PHI(c) | | Pepco(c) | | DPL(c) | | ACE(c) | |
| 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 | 9.3 | | 0 | | 12.7 | | (3.4) | | 5.5 | | 5.0 | | 4.2 | | 6.5 | | 6.8 | |
| Qualified NDT fund income | 3.2 | | 10.0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Deferred Prosecution Agreement payments | 2.5 | | 0 | | 9.4 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.2) | | (3.2) | | (0.3) | | 0 | | (0.1) | | (0.2) | | (0.1) | | (0.3) | | (0.5) | |
| Plant basis differences | (4.0) | | 0 | | (0.9) | | (15.9) | | (1.8) | | (2.2) | | (2.4) | | (0.5) | | (3.7) | |
| Production tax credits and other credits | (2.6) | | (7.0) | | (0.4) | | 0 | | (0.4) | | (0.3) | | (0.3) | | (0.2) | | (0.4) | |
| Noncontrolling interests | 1.0 | | 3.1 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Excess deferred tax amortization | (15.8) | | 0 | | (11.8) | | (3.5) | | (15.0) | | (45.3) | | (29.2) | | (53.6) | | (81.4) | |
| Tax settlements | (5.0) | | (15.7) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Other | 0.1 | | (0.5) | | 2.1 | | (0.5) | | (0.5) | | (0.6) | | (0.8) | | (1.1) | | 0 | |
| Effective income tax rate | 8.5% | | 7.7% | | 31.8% | | (2.3)% | | 8.7% | | (22.6)% | | (7.6)% | | (28.2)% | | (58.2)% | |
94
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation |
| 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) | $ | 1,243 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,243 |
| | $ | 581 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 581 |
|
| 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 |
|
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 48 |
| | — |
| | — |
| | — |
| | 48 |
| | 5 |
| | — |
| | — |
| | — |
| | 5 |
|
| Mutual funds | 72 |
| | — |
| | — |
| | — |
| | 72 |
| | 24 |
| | — |
| | — |
| | — |
| | 24 |
|
| Fixed income | — |
| | 15 |
| | — |
| | — |
| | 15 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Life insurance contracts | — |
| | 70 |
| | 38 |
| | — |
| | 108 |
| | — |
| | 22 |
| | — |
| | — |
| | 22 |
|
| Rabbi trust investments subtotal | 120 |
|
| 85 |
|
| 38 |
| | — |
|
| 243 |
|
| 29 |
|
| 22 |
|
| — |
| | — |
|
| 51 |
|
| 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)(f) | (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 |
|
| Total assets | 6,573 |
|
| 4,155 |
|
| 1,396 |
|
| 3,433 |
|
| 15,557 |
|
| 5,820 |
|
| 4,092 |
|
| 1,358 |
|
| 3,433 |
|
| 14,703 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Fair ValueIncome Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 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 | 5.1 | | 4.2 | | 8.2 | | 0 | | 6.4 | | 4.8 | | 2.0 | | 6.7 | | 6.9 |
| Qualified NDT fund income | 5.3 | | 11.9 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.9) | | (4.0) | | (0.2) | | 0 | | (0.1) | | (0.2) | | (0.1) | | (0.2) | | (0.3) |
| Plant basis differences | (1.6) | | 0 | | (0.7) | | (6.8) | | (1.1) | | (1.8) | | (2.3) | | (0.6) | | (2.0) |
| Production tax credits and other credits | (1.0) | | (2.1) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Noncontrolling interests | (1.0) | | (2.3) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Excess deferred tax amortization | (6.0) | | 0 | | (9.2) | | (2.9) | | (7.9) | | (18.6) | | (17.3) | | (15.0) | | (23.4) |
| Other | 0.8 | | (0.1) | | 0.2 | | (0.2) | | 0.1 | | 0.5 | | 0.7 | | 0.2 | | 0 |
| Effective income tax rate | 20.7% | | 28.6% | | 19.3% | | 11.1% | | 18.4% | | 5.7% | | 4.0% | | 12.1% | | 2.2% |
__________
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)At PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to storm repairs.
(c)At BGE, PHI, Pepco, DPL, and ACE, the lower effective tax rate is primarily attributable to accelerated amortization of Financial Assets and Liabilities
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation |
| 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 | ) | | (1,276 | ) | | — |
| | (4,881 | ) | | (642 | ) | | (2,963 | ) | | (1,027 | ) | | — |
| | (4,632 | ) |
| Proprietary trading | — |
| | (73 | ) | | (21 | ) | | — |
| | (94 | ) | | — |
| | (73 | ) | | (21 | ) | | — |
| | (94 | ) |
Effect of netting and allocation of collateral(e)(f) | 639 |
| | 2,581 |
| | 808 |
| | — |
| | 4,028 |
| | 639 |
| | 2,581 |
| | 808 |
| | — |
| | 4,028 |
|
| Commodity derivative liabilities subtotal | (3 | ) |
| (455 | ) |
| (489 | ) | | — |
|
| (947 | ) |
| (3 | ) |
| (455 | ) |
| (240 | ) | | — |
|
| (698 | ) |
| Deferred compensation obligation | — |
| | (137 | ) | | — |
| | — |
| | (137 | ) | | — |
| | (35 | ) | | — |
| | — |
| | (35 | ) |
| Total liabilities | (3 | ) |
| (592 | ) |
| (489 | ) | | — |
|
| (1,084 | ) |
| (3 | ) |
| (490 | ) |
| (240 | ) | | — |
|
| (733 | ) |
| Total net assets | $ | 6,570 |
|
| $ | 3,563 |
|
| $ | 907 |
| | $ | 3,433 |
|
| $ | 14,473 |
|
| $ | 5,817 |
|
| $ | 3,602 |
|
| $ | 1,118 |
| | $ | 3,433 |
|
| $ | 13,970 |
|
_________
| |
(a) | Exelon excludes cash of $347 million and $458 million at September 30, 2019 and December 31, 2018, respectively, and restricted cash of $112 million and $80 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $186 million and $185 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $183 million and $283 million at September 30, 2019 and December 31, 2018, respectively, and restricted cash of $66 million and $39 million at September 30, 2019 and December 31, 2018, respectively. |
| |
(b) | Includes $85 million and $50 million of cash received from outstanding repurchase agreements at September 30, 2019 and December 31, 2018, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below. |
| |
(c) | Includes a derivative liability of $2 million and a derivative asset of $44 million, which have total notional amounts of $864 million and $1,432 million at September 30, 2019 and December 31, 2018, 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 Exelon and Generation's exposure to credit or market loss. |
| |
(d) | Excludes nettransmission related deferred income tax regulatory liabilities of $176 million and $130 million at September 30, 2019 and December 31, 2018, 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. |
| |
(e) | Collateral posted/(received) from counterparties totaled $93 million, $324 million and $304 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2019. Collateral posted/(received) from counterparties, net of collateral paid to 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. |
| |
(f) | Of the collateral posted/(received), $306 million and $(94) million represents variation margin on the exchanges as of September 30, 2019 and December 31, 2018, respectively. |
As of September 30, 2019, Exelon and Generation have outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $93 million, $241 million, $383 million, and $388 million, respectively. These commitments will be funded by Generation’s existing NDT funds.
Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $75 million as of September 30, 2019. Changes were immaterial in fair value, cumulative adjustments and impairments for the three and nine months ended September 30, 2019.
Valuation Techniques Used to Determine Net Asset Value
Certain NDT Fund Investments are not classified within the fair value hierarchy and are included under the heading “Not subject to leveling” in the table above. These investments are measured at fair value using NAV per share as a practical expedientresult of regulatory settlements. See Note 2 — Regulatory Matters for additional information.
(d)At Generation, the lower effective tax rate is primarily attributable to tax settlements.
(e)At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. See Note 14 — Commitments and include commingled funds, mutual funds which are not publicly quoted, managed middle market funds, private equity and real estate funds.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Fair ValueIncome Taxes
Accounting for Uncertainty in Income Taxes
Exelon, Generation, PHI, and ACE have the following unrecognized tax benefits as of Financial AssetsSeptember 30, 2020 and Liabilities
For commingled fundsDecember 31, 2019. ComEd, PECO, BGE, Pepco, and mutual funds, whichDPL's amounts are not publicly quoted,material.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | | | PHI | | ACE |
| September 30, 2020 | $ | 125 | | | $ | 49 | | | | | $ | 53 | | | $ | 16 | |
| December 31, 2019 | 507 | | | 441 | | | | | 48 | | | 14 | |
Exelon's and Generation's unrecognized federal and state tax benefits decreased in the fair valuefirst 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.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
The following table represents Exelon's, PHI's, and ACE's 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 as of September 30, 2020. Generation's, ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.
| | | | | | | | | | | | | | |
| Exelon | | PHI | | ACE(a) |
| $ | 14 | | | $ | 14 | | | $ | 14 | |
__________
(a)The unrecognized tax benefit related to ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Other Income Tax Matters
State Income Tax Law Changes
On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for tax years beginning on or after January 1, 2021. The tax rate is primarily derived from the quoted pricescontingent upon ratification of state constitutional amendments in active markets on the underlying securities and can typically be redeemed monthly with 30 or less days of notice and without further restrictions. For managed middle market 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 maturityNovember 2020. The effect of the term loan. Private equityrate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation, and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that areComEd do not publicly traded onexpect a stock exchange, suchmaterial impact to their financial statements as leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. 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 understandingresult of the investment funds. Private equityrate change.
Long-Term Marginal State Income Tax Rate (All Registrants)
In the third quarter of 2020 and real estate valuations2019, Exelon updated its marginal state income tax rates for changes in state apportionment. The changes in marginal rates in the third quarter of 2020 resulted in an increase of $66 million and a decrease of $26 million to the deferred income tax liability at Exelon and Generation, respectively, as of September 30, 2020. The changes in marginal rates in the third quarter of 2019 resulted in an increase of $23 million and $9 million to the deferred income tax liability at Exelon and Generation, respectively, as of September 30, 2019. Exelon and Generation recorded a corresponding adjustment to income tax expense, net of federal taxes, in each of those respective periods.
Allocation of Tax Benefits (All Registrants)
Generation and the Utility Registrants are reported byall party to an agreement with Exelon and other subsidiaries of Exelon that provides for the fund managerallocation of consolidated tax liabilities and are based onbenefits (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 valuationparty been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisalsparty receiving the benefit.
The following table presents the allocation of federal tax benefits from sources with professional qualifications. These valuation inputs are unobservable.
ComEd, PECO and BGEExelon under the Tax Sharing Agreement.
96
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | ComEd | | PECO | | BGE |
| As of September 30, 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) | $ | 264 |
| | $ | — |
| | $ | — |
| | $ | 264 |
| | $ | 207 |
| | $ | — |
| | $ | — |
| | $ | 207 |
| | $ | 122 |
| | $ | — |
| | $ | — |
| | $ | 122 |
|
| Rabbi trust investments | | | | | | |
| | | | | | | |
| | | | | | | |
|
| Mutual funds | — |
| | — |
| | — |
| | — |
| | 8 |
| | — |
| | — |
| | 8 |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Life insurance contracts | — |
| | — |
| | — |
| | — |
| | — |
| | 11 |
| | — |
| | 11 |
| | — |
| | — |
| | — |
| | — |
|
| Rabbi trust investments subtotal | — |
|
| — |
|
| — |
|
| — |
|
| 8 |
|
| 11 |
|
| — |
|
| 19 |
|
| 7 |
|
| — |
|
| — |
|
| 7 |
|
| Total assets | 264 |
|
| — |
|
| — |
|
| 264 |
|
| 215 |
|
| 11 |
|
| — |
|
| 226 |
|
| 129 |
|
| — |
|
| — |
|
| 129 |
|
| Liabilities | | | | | | |
| | | | | | | |
| | | | | | | |
|
| Deferred compensation obligation | — |
| | (7 | ) | | — |
| | (7 | ) | | — |
| | (8 | ) | | — |
| | (8 | ) | | — |
| | (5 | ) | | — |
| | (5 | ) |
Mark-to-market derivative liabilities(b) | — |
| | — |
| | (280 | ) | | (280 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total liabilities | — |
| | (7 | ) | | (280 | ) | | (287 | ) | | — |
| | (8 | ) | | — |
| | (8 | ) | | — |
| | (5 | ) | | — |
| | (5 | ) |
| Total net assets (liabilities) | $ | 264 |
| | $ | (7 | ) | | $ | (280 | ) | | $ | (23 | ) | | $ | 215 |
| | $ | 3 |
| | $ | — |
| | $ | 218 |
| | $ | 129 |
| | $ | (5 | ) | | $ | — |
| | $ | 124 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | — |
|
| — |
|
| — |
|
| — |
|
| 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(b) | — |
| | — |
| | (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 9 — Fair ValueIncome Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| September 30, 2020 | $ | 64 | | | $ | 14 | | | $ | 17 | | | $ | 0 | | | $ | 17 | | | $ | 8 | | | $ | 6 | | | $ | 1 | |
| December 31, 2019 | 41 | | | 0 | | | 14 | | | 3 | | | 7 | | | 6 | | | 1 | | | 0 | |
10. Retirement Benefits (All Registrants)
Defined Benefit Pension and OPEB
During the first quarter of Financial Assets2020, Exelon received an updated valuation of its pension and Liabilities
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.
_________
| |
(a) | ComEd excludes cash of $76 million and $93 million at September 30, 2019 and December 31, 2018, respectively, and restricted cash of $31 million and $28 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $171 million and $166 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $23 million and $24 million at September 30, 2019 and December 31, 2018, respectively. BGE excludes cash of $8 million and $7 million at September 30, 2019 and December 31, 2018, respectively, and restricted cash of $1 million and $2 million at September 30, 2019 and December 31, 2018, respectively. |
| |
(b) | The Level 3 balance consists of the current and noncurrent liability of $27 million and $253 million, respectively, at September 30, 2019, and $26 million and $223 million, respectively, at December 31, 2018, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
PHI, Pepco, DPLA 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 three and ACEnine months ended September 30, 2020 and 2019.
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Pension Benefits | | OPEB |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| Components of net periodic benefit cost: | | | | | | | |
| Service cost | $ | 97 | | | $ | 89 | | | $ | 22 | | | $ | 23 | |
| Interest cost | 190 | | | 221 | | | 37 | | | 47 | |
| Expected return on assets | (317) | | | (306) | | | (41) | | | (38) | |
| Amortization of: | | | | | | | |
| Prior service cost (benefit) | 1 | | | 0 | | | (30) | | | (45) | |
| Actuarial loss | 128 | | | 104 | | | 12 | | | 11 | |
| Settlement charges | 8 | | | 7 | | | 0 | | | 0 | |
| Contractual termination benefits | 0 | | | 1 | | | 0 | | | 0 | |
| Net periodic benefit cost | $ | 107 | | | $ | 116 | | | $ | 0 | | | $ | (2) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Pension Benefits | | OPEB |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
| Components of net periodic benefit cost: | | | | | | | |
| Service cost | $ | 290 | | | $ | 267 | | | $ | 67 | | | $ | 70 | |
| Interest cost | 569 | | | 663 | | | 114 | | | 141 | |
| Expected return on assets | (953) | | | (918) | | | (122) | | | (115) | |
| Amortization of: | | | | | | | |
| Prior service cost (benefit) | 3 | | | 0 | | | (92) | | | (134) | |
| Actuarial loss | 384 | | | 310 | | | 36 | | | 34 | |
| Settlement charges | 14 | | | 7 | | | 0 | | | 0 | |
| Contractual termination benefits | 0 | | | 1 | | | 0 | | | 0 | |
| Net periodic benefit cost | $ | 307 | | | $ | 330 | | | $ | 3 | | | $ | (4) | |
97
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of September 30, 2019 | | As of December 31, 2018 |
| PHI | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 107 |
| | $ | — |
| | $ | — |
| | $ | 107 |
| | $ | 147 |
| | $ | — |
| | $ | — |
| | $ | 147 |
|
| Rabbi trust investments | | | | | | |
| | | | | | | |
|
| Cash equivalents | 43 |
| | — |
| | — |
| | 43 |
| | 42 |
| | — |
| | — |
| | 42 |
|
| Mutual funds | 13 |
| | — |
| | — |
| | 13 |
| | 13 |
| | — |
| | — |
| | 13 |
|
| Fixed income | — |
| | 13 |
| | — |
| | 13 |
| | — |
| | 15 |
| | — |
| | 15 |
|
| Life insurance contracts | — |
| | 24 |
| | 40 |
| | 64 |
| | — |
| | 22 |
| | 38 |
| | 60 |
|
| Rabbi trust investments subtotal | 56 |
|
| 37 |
|
| 40 |
|
| 133 |
|
| 55 |
|
| 37 |
|
| 38 |
|
| 130 |
|
| Total assets | 163 |
|
| 37 |
|
| 40 |
|
| 240 |
| | 202 |
|
| 37 |
|
| 38 |
|
| 277 |
|
| Liabilities | | | | | | |
| | | | | | | |
|
| Deferred compensation obligation | — |
| | (19 | ) | | — |
| | (19 | ) | | — |
| | (21 | ) | | — |
| | (21 | ) |
| Total liabilities | — |
|
| (19 | ) |
| — |
|
| (19 | ) |
| — |
|
| (21 | ) |
| — |
|
| (21 | ) |
| Total net assets | $ | 163 |
|
| $ | 18 |
|
| $ | 40 |
|
| $ | 221 |
| | $ | 202 |
|
| $ | 16 |
|
| $ | 38 |
|
| $ | 256 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pepco | | DPL | | ACE |
| As of September 30, 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 |
| | $ | — |
| | $ | — |
| | $ | 34 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
|
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 43 |
| | — |
| | — |
| | 43 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Fixed income | — |
| | 3 |
| | — |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Life insurance contracts | — |
| | 24 |
| | 40 |
| | 64 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Rabbi trust investments subtotal | 43 |
|
| 27 |
|
| 40 |
|
| 110 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| Total assets | 77 |
|
| 27 |
|
| 40 |
|
| 144 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 18 |
|
| — |
|
| — |
|
| 18 |
|
| Liabilities |
| |
| |
| |
|
| |
| |
| |
| |
| |
| |
| |
| |
|
| Deferred compensation obligation | — |
| | (2 | ) | | — |
| | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total liabilities | — |
|
| (2 | ) |
| — |
|
| (2 | ) |
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| Total net assets | $ | 77 |
| | $ | 25 |
| | $ | 40 |
| | $ | 142 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 910 — Fair ValueRetirement Benefits
The amounts below represent the Registrants' allocated pension and OPEB plan 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Pension and OPEB Costs | | 2020 | | 2019 | | 2020 | | 2019 |
| Exelon | | $ | 107 | | | $ | 114 | | | $ | 310 | | | $ | 326 | |
| Generation | | 30 | | | 37 | | | 89 | | | 100 | |
| ComEd | | 29 | | | 23 | | | 85 | | | 70 | |
| PECO | | 1 | | | 4 | | | 4 | | | 9 | |
| BGE | | 16 | | | 16 | | | 47 | | | 47 | |
| PHI | | 17 | | | 23 | | | 52 | | | 71 | |
| Pepco | | 4 | | | 6 | | | 11 | | | 19 | |
| DPL | | 2 | | | 4 | | | 6 | | | 11 | |
| ACE | | 3 | | | 4 | | | 10 | | | 12 | |
Defined Contribution Savings Plans
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of Financial Assetsthe IRC and Liabilities
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | 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 |
|
_________
| |
(a) | PHI excludes cash of $45 million and $39 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $15 million and $19 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $18 million and $15 million at September 30, 2019 and December 31, 2018, respectively. DPL excludes cash of $11 million and $8 million at September 30, 2019 and December 31, 2018, respectively. ACE excludes cash of $13 million and $7 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $15 million and $19 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. |
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 tables presenttable presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basismatching contributions to the savings plans during the three and nine months ended September 30, 2020 and 2019, and 2018:respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Savings Plan Matching Contributions | | 2020 | | 2019 | | 2020 | | 2019 |
| Exelon | | $ | 37 | | | $ | 36 | | | $ | 104 | | | $ | 101 | |
| Generation | | 14 | | | 14 | | | 41 | | | 41 | |
| ComEd | | 9 | | | 9 | | | 25 | | | 26 | |
| PECO | | 3 | | | 2 | | | 8 | | | 7 | |
| BGE | | 4 | | | 4 | | | 8 | | | 9 | |
| PHI | | 3 | | | 4 | | | 9 | | | 8 | |
| Pepco | | 1 | | | 1 | | | 3 | | | 2 | |
| DPL | | 1 | | | 1 | | | 2 | | | 2 | |
| ACE | | 0 | | | 1 | | | 1 | | | 1 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PHI and Pepco | | |
| Three Months Ended September 30, 2019 | Total | | NDT Fund Investments | | Mark-to-Market Derivatives | | Total Generation | | Mark-to-Market Derivatives | | Life Insurance Contracts | | Eliminated in Consolidation |
| Balance as of June 30, 2019 | $ | 1,179 |
| | $ | 539 |
| | $ | 873 |
| | $ | 1,412 |
| | $ | (273 | ) | | $ | 40 |
| | $ | — |
|
| Total realized / unrealized gains (losses) |
| | | | | |
| | | | | | |
| Included in net income | (171 | ) | | 2 |
| | (173 | ) | (a) | (171 | ) | | — |
| | — |
| | — |
|
| Included in noncurrent payables to affiliates | — |
| | 11 |
| | — |
| | 11 |
| | — |
| | — |
| | (11 | ) |
| Included in regulatory assets/liabilities | 4 |
| | — |
| | — |
| | — |
| | (7 | ) | (b) | — |
| | 11 |
|
| Change in collateral | 41 |
| | — |
| | 41 |
| | 41 |
| | — |
| | — |
| | — |
|
| Purchases, sales, issuances and settlements |
|
| | | | | |
| | | | | | |
| Purchases | 53 |
| | 1 |
| | 52 |
| | 53 |
| | — |
| | — |
| | — |
|
| Sales | (22 | ) | | (21 | ) | | (1 | ) | | (22 | ) | | — |
| | — |
| | — |
|
| Settlements | (18 | ) | | (18 | ) | | — |
| | (18 | ) | | — |
| | — |
| | — |
|
| Transfers into Level 3 | 1 |
| | — |
| | 1 |
| (c) | 1 |
| | — |
| | — |
| | — |
|
| Transfers out of Level 3 | (11 | ) | | — |
| | (11 | ) | (c) | (11 | ) | | — |
| | — |
| | — |
|
| Balance at September 30, 2019 | $ | 1,056 |
| | $ | 514 |
| | $ | 782 |
| | $ | 1,296 |
| | $ | (280 | ) | | $ | 40 |
| | $ | — |
|
| The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2019 | $ | (18 | ) | | $ | 2 |
| | $ | (20 | ) | | $ | (18 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Fair Value of Financial Assets and Liabilities
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PHI and Pepco | | |
| Nine Months Ended September 30, 2019 | Total | | NDT Fund Investments | | Mark-to-Market Derivatives | | Total Generation | | Mark-to-Market Derivatives | | Life Insurance Contracts | | Eliminated in Consolidation |
| Balance as of December 31, 2018 | $ | 907 |
| | $ | 543 |
| | $ | 575 |
| | $ | 1,118 |
| | $ | (249 | ) | | $ | 38 |
| | $ | — |
|
| Total realized / unrealized gains (losses) |
|
| | | | | |
|
| | | | | | |
| Included in net income | (125 | ) | | 5 |
| | (132 | ) | (a) | (127 | ) | | — |
| | 2 |
| | — |
|
| Included in noncurrent payables to affiliates | — |
| | 32 |
| | — |
| | 32 |
| | — |
| | — |
| | (32 | ) |
| Included in regulatory assets | 1 |
| | — |
| | — |
| | — |
| | (31 | ) | (b) | — |
| | 32 |
|
| Change in collateral | 227 |
| | — |
| | 227 |
| | 227 |
| | — |
| | — |
| | — |
|
| Purchases, sales, issuances and settlements |
|
| | | | | |
|
| | | | | | |
| Purchases | 163 |
| | 43 |
| | 120 |
| | 163 |
| | — |
| | — |
| | — |
|
| Sales | (23 | ) | | (21 | ) | | (2 | ) | | (23 | ) | | — |
| | — |
| | — |
|
| Settlements | (88 | ) | | (88 | ) | | — |
| | (88 | ) | | — |
| | — |
| | — |
|
| Transfers into Level 3 | 5 |
| | — |
| | 5 |
| (c) | 5 |
| | — |
| | — |
| | — |
|
| Transfers out of Level 3 | (11 | ) | | — |
| | (11 | ) | (c) | (11 | ) | | — |
| | — |
| | — |
|
| Balance as of September 30, 2019 | $ | 1,056 |
| | $ | 514 |
| | $ | 782 |
| | $ | 1,296 |
| | $ | (280 | ) | | $ | 40 |
| | $ | — |
|
| The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2019 | $ | 173 |
| | $ | 5 |
| | $ | 166 |
| | $ | 171 |
| | $ | — |
| | $ | 2 |
| | $ | — |
|
__________
| |
(a) | Includes a reduction for the reclassification of $153 million and $298 million of realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2019, respectively.
|
| |
(b) | Includes $7 million of decreases in fair value and an increase for realized losses due to settlements of $4 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2019. Includes $31 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 nine months ended September 30, 2019. |
| |
(c) | 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. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Fair Value of Financial Assets and Liabilities
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PHI and Pepco | | |
| Three Months Ended September 30, 2018 | Total | | NDT Fund Investments | | Mark-to-Market Derivatives | | Total Generation | | Mark-to-Market Derivatives | | Life Insurance Contracts | �� | Eliminated in Consolidation |
| Balance as of June 30, 2018 | $ | 1,106 |
| | $ | 585 |
| | $ | 737 |
| | $ | 1,322 |
| | $ | (252 | ) | | $ | 36 |
| | $ | — |
|
| Total realized / unrealized gains (losses) | | | | | | |
|
| | | | | | |
| Included in net income | (259 | ) | | (1 | ) | | (259 | ) | (a) | (260 | ) | | — |
| | 1 |
| | — |
|
| Included in noncurrent payables to affiliates | — |
| | (4 | ) | | — |
| | (4 | ) | | — |
| | — |
| | 4 |
|
| Included in regulatory assets | (11 | ) | | — |
| | — |
| | — |
| | (7 | ) | (b) | — |
| | (4 | ) |
| Change in collateral | (44 | ) | | — |
| | (44 | ) | | (44 | ) | | — |
| | — |
| | — |
|
| Purchases, sales, issuances and settlements |
| | | | | |
|
| | | | | | |
| Purchases | 96 |
| | 15 |
| | 81 |
| | 96 |
| | — |
| | — |
| | — |
|
| Settlements | (29 | ) | | (29 | ) | | — |
| | (29 | ) | | — |
| | — |
| | — |
|
| Transfers into Level 3 | 3 |
| | — |
| | 3 |
| (c) | 3 |
| | — |
| | — |
| | — |
|
| Transfers out of Level 3 | (6 | ) | | — |
| | (6 | ) | (c) | (6 | ) | | — |
| | — |
| | — |
|
| Balance as of September 30, 2018 | $ | 856 |
| | $ | 566 |
|
| $ | 512 |
|
| $ | 1,078 |
|
| $ | (259 | ) |
| $ | 37 |
| | $ | — |
|
| The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2018 | $ | (105 | ) | | $ | (1 | ) | | $ | (104 | ) | | $ | (105 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PHI and Pepco | | |
| Nine Months Ended September 30, 2018 | Total | | NDT Fund Investments | | Mark-to-Market Derivatives | | Total Generation | | Mark-to-Market Derivatives | | Life Insurance Contracts | | Eliminated in Consolidation |
| Balance as of December 31, 2017 | $ | 966 |
| | $ | 648 |
| | $ | 552 |
| | $ | 1,200 |
| | $ | (256 | ) | | $ | 22 |
| | $ | — |
|
| Total realized / unrealized gains (losses) |
| | | | | |
|
| | | | | | |
| Included in net income | (186 | ) | | (1 | ) | | (188 | ) | (a) | (189 | ) | | — |
| | 3 |
| | — |
|
| Included in regulatory assets | (3 | ) | | — |
| | — |
| | — |
| | (3 | ) | (b) | — |
| | — |
|
| Change in collateral | 14 |
| | — |
| | 14 |
| | 14 |
| | — |
| | — |
| | — |
|
| Purchases, sales, issuances and settlements |
| | | | | |
|
| | | | | | |
| Purchases | 215 |
| | 34 |
| | 181 |
| | 215 |
| | — |
| | — |
| | — |
|
| Sales | (3 | ) | | — |
| | (3 | ) | | (3 | ) | | — |
| | — |
| | — |
|
| Settlements | (103 | ) | | (115 | ) | | — |
| | (115 | ) | | — |
| | 12 |
| | — |
|
| Transfers into Level 3 | (21 | ) | | — |
| | (21 | ) | (c) | (21 | ) | | — |
| | — |
| | — |
|
| Transfers out of Level 3 | (23 | ) | | — |
| | (23 | ) | (c) | (23 | ) | | — |
| | — |
| | — |
|
| Balance as of September 30, 2018 | $ | 856 |
| | $ | 566 |
| | $ | 512 |
| | $ | 1,078 |
|
| $ | (259 | ) | | $ | 37 |
| | $ | — |
|
| The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2018 | $ | 154 |
| | $ | (5 | ) | | $ | 159 |
| | $ | 154 |
| | $ | — |
| | $ | — |
| | $ | — |
|
__________
| |
(a) | Includes a reduction for the reclassification of $155 million and $347 million of realized losses due to the settlement of derivative contracts for the three and nine months ended September 30, 2018, respectively. |
| |
(b) | Includes $4 million of increases in fair value and an increase for realized losses due to settlements of $3 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2018. Includes $9 million of decreases in fair value and an increase for realized losses due to settlements of $12 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2018.
|
| |
(c) | 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. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Fair Value of Financial Assets and Liabilities
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 three and nine months ended September 30, 2019 and 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 realized (losses) gains for the three months ended September 30, 2019 | $ | (25 | ) | | $ | (148 | ) | | $ | — |
| | $ | 2 |
| | $ | (25 | ) | | $ | (148 | ) | | $ | 2 |
| | $ | — |
|
| Total realized gains (losses) for the nine months ended September 30, 2019 | 122 |
| | (254 | ) | | — |
| | 5 |
| | 122 |
| | (254 | ) | | 5 |
| | — |
|
| Total unrealized gains (losses) for the three months ended September 30, 2019 | 99 |
| | (119 | ) | | — |
| | 2 |
| | 99 |
| | (119 | ) | | 2 |
| | — |
|
| Total unrealized gains (losses) for the nine months ended September 30, 2019 | 368 |
| | (202 | ) | | 2 |
| | 5 |
| | 368 |
| | (202 | ) | | 5 |
| | 2 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 realized (losses) gains for the three months ended September 30, 2018 | $ | (176 | ) | | $ | (83 | ) | | $ | 1 |
| | $ | (1 | ) | | $ | (176 | ) | | $ | (83 | ) | | $ | (1 | ) | | $ | 1 |
|
| Total realized (losses) gains for the nine months ended September 30, 2018 | (32 | ) | | (156 | ) | | 3 |
| | (1 | ) | | (32 | ) | | (156 | ) | | (1 | ) | | 3 |
|
| Total unrealized (losses) for the three months ended September 30, 2018 | (64 | ) | | (40 | ) | | — |
| | (1 | ) | | (64 | ) | | (40 | ) | | (1 | ) | | — |
|
| Total unrealized gains (losses) for the nine months ended September 30, 2018 | 174 |
| | (15 | ) |
| — |
|
| (5 | ) | | 174 |
| | (15 | ) | | (5 | ) | | — |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Fair Value of Financial Assets and Liabilities
The table below discloses the significant inputs to the forward curve used to value these positions.
|
| | | | | | | | | | | | | | | | | | | | |
| Type of trade | | Fair Value at September 30, 2019 | | Fair Value at December 31, 2018 | | Valuation Technique | | Unobservable Input | | 2019 Range | | 2018 Range |
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b) | | $ | 411 |
| | $ | 443 |
| | Discounted
Cash Flow | | Forward power
price | | $11 | - | $167 | | $12 | - | $174 |
| | |
|
| | | |
| | Forward gas
price | | $1.36 | - | $10.82 | | $0.78 | - | $12.38 |
| | |
|
| | | | Option
Model | | Volatility
percentage | | 9% | - | 200% | | 10% | - | 277% |
| | | | | | | | | | | | | | | | | |
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b) | | $ | 67 |
| | $ | 56 |
| | Discounted
Cash Flow | | Forward power
price | | $17 | - | $167 | | $14 | - | $174 |
| | | | | | | | | | | | | | | | | |
| Mark-to-market derivatives (Exelon and ComEd) | | $ | (280 | ) | | $ | (249 | ) | | Discounted
Cash Flow | | Forward heat
rate(c) | | 9x | - | 10x | | 10x | - | 11x |
| | | | | | | | | Marketability
reserve | | 4% | - | 7% | | 4% | - | 8% |
| | | | | | | | | Renewable
factor | | 87% | - | 119% | | 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 $304 million and $76 million as of September 30, 2019 and December 31, 2018, 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.
10.11. 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1011 — Derivative Financial Instruments
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 referencing 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 that 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.
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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Derivative Financial Instruments
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Derivative Financial Instruments
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 20%15% 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 priceand 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 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 4 - 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 September 30, 2019 and December 31, 2018 and is not presented in the fair value tables below. |
(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 September 30, 2020 and December 31, 2019 and is not presented in the fair value tables below.
The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of September 30, 2020 and December 31, 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2020 | | Exelon | | Generation | | ComEd | | | | |
| Derivatives | | Total
Derivatives | | Economic
Hedges | | Proprietary
Trading | | Collateral(a)(b) | | Netting(a) | | Subtotal | | Economic
Hedges | | | | | | | | |
Mark-to-market derivative assets
(current assets) | | $ | 471 | | | $ | 2,566 | | | $ | 58 | | | $ | 79 | | | $ | (2,232) | | | $ | 471 | | | $ | 0 | | | | | | | | | |
Mark-to-market derivative assets
(noncurrent assets) | | 383 | | | 1,500 | | | 16 | | | 39 | | | (1,172) | | | 383 | | | 0 | | | | | | | | | |
| Total mark-to-market derivative assets | | 854 | | | 4,066 | | | 74 | | | 118 | | | (3,404) | | | 854 | | | 0 | | | | | | | | | |
Mark-to-market derivative liabilities
(current liabilities) | | (168) | | | (2,414) | | | (40) | | | 84 | | | 2,232 | | | (138) | | | (30) | | | | | | | | | |
Mark-to-market derivative liabilities
(noncurrent liabilities) | | (378) | | | (1,313) | | | (12) | | | 49 | | | 1,172 | | | (104) | | | (274) | | | | | | | | | |
| Total mark-to-market derivative liabilities | | (546) | | | (3,727) | | | (52) | | | 133 | | | 3,404 | | | (242) | | | (304) | | | | | | | | | |
| Total mark-to-market derivative net assets (liabilities) | | $ | 308 | | | $ | 339 | | | $ | 22 | | | $ | 251 | | | $ | 0 | | | $ | 612 | | | $ | (304) | | | | | | | | | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1011 — Derivative Financial Instruments
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2019 | | Exelon | | Generation | | ComEd | | | | |
| Description | | Total
Derivatives | | Economic
Hedges | | Proprietary
Trading | | Collateral(a)(b) | | Netting(a) | | Subtotal | | Economic
Hedges | | | | | | | | |
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) | | | | | | | | | |
The following table provides a summary of_________
(a)Exelon and Generation net all available amounts allowed under the derivative fair value balances recorded byauthoritative 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 ComEdpayables, 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/(received), $34 million and $511 million represents variation margin on the exchanges at September 30, 20192020 and December 31, 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2019 | | Exelon | | Generation | | ComEd |
| Derivatives | | Total
Derivatives | | Economic Hedges | | Proprietary Trading | | Collateral
(a)(b) | | Netting (a) | | Subtotal | | Economic Hedges |
Mark-to-market derivative assets (current assets) | | $ | 602 |
| | $ | 2,452 |
| | $ | 143 |
| | $ | 212 |
| | $ | (2,205 | ) | | $ | 602 |
| | $ | — |
|
Mark-to-market derivative assets (noncurrent assets) | | 483 |
| | 1,386 |
| | 67 |
| | 104 |
| | (1,074 | ) | | 483 |
| | — |
|
| Total mark-to-market derivative assets | | 1,085 |
| | 3,838 |
| | 210 |
| | 316 |
| | (3,279 | ) | | 1,085 |
| | — |
|
Mark-to-market derivative liabilities (current liabilities) | | (224 | ) | | (2,550 | ) | | (101 | ) | | 249 |
| | 2,205 |
| | (197 | ) | | (27 | ) |
Mark-to-market derivative liabilities (noncurrent liabilities) | | (394 | ) | | (1,324 | ) | | (47 | ) | | 156 |
| | 1,074 |
| | (141 | ) | | (253 | ) |
| Total mark-to-market derivative liabilities | | (618 | ) | | (3,874 | ) | | (148 | ) | | 405 |
| | 3,279 |
| | (338 | ) | | (280 | ) |
| Total mark-to-market derivative net assets (liabilities) | | $ | 467 |
| | $ | (36 | ) | | $ | 62 |
| | $ | 721 |
| | $ | — |
| | $ | 747 |
| | $ | (280 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2018 | | Exelon | | Generation | | ComEd |
| Description | | Total
Derivatives | | Economic
Hedges | | Proprietary
Trading | | Collateral
(a)(b) | | Netting (a) | | Subtotal | | Economic
Hedges |
Mark-to-market derivative assets
(current assets) | | $ | 801 |
| | $ | 3,505 |
| | $ | 105 |
| | $ | 121 |
| | $ | (2,930 | ) | | $ | 801 |
| | $ | — |
|
Mark-to-market derivative assets
(noncurrent assets) | | 445 |
| | 1,266 |
| | 41 |
| | 51 |
| | (913 | ) | | 445 |
| | — |
|
| Total mark-to-market derivative assets | | 1,246 |
| | 4,771 |
| | 146 |
| | 172 |
| | (3,843 | ) | | 1,246 |
| | — |
|
Mark-to-market derivative liabilities
(current liabilities) | | (473 | ) | | (3,429 | ) | | (74 | ) | | 125 |
| | 2,931 |
| | (447 | ) | | (26 | ) |
Mark-to-market derivative liabilities
(noncurrent liabilities) | | (474 | ) | | (1,203 | ) | | (20 | ) | | 60 |
| | 912 |
| | (251 | ) | | (223 | ) |
| Total mark-to-market derivative liabilities | | (947 | ) | | (4,632 | ) | | (94 | ) | | 185 |
| | 3,843 |
| | (698 | ) | | (249 | ) |
| Total mark-to-market derivative net assets (liabilities) | | $ | 299 |
| | $ | 139 |
| | $ | 52 |
| | $ | 357 |
| | $ | — |
| | $ | 548 |
| | $ | (249 | ) |
_________
| |
(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 immaterial and not reflected in the table above. |
| |
(b) | Of the collateral posted/(received), $306 million and $(94) million represents variation margin on the exchanges at September 30, 2019 and December 31, 2018 respectively. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Derivative Financial Instruments
Economic Hedges (Commodity Price Risk)
Generation. For the three and nine months ended September 30, 20192020 and 2018,2019, 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.
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | | 2019 | | 2018 | | 2019 | | 2018 |
| Income Statement Location | | Gain (Loss) | | Gain (Loss) |
| Operating revenues | | $ | 76 |
| | $ | 8 |
| | $ | 65 |
| | $ | (99 | ) |
| Purchased power and fuel | | (45 | ) | | 66 |
| | (127 | ) | | (4 | ) |
| Total Exelon and Generation | | $ | 31 |
| | $ | 74 |
| | $ | (62 | ) | | $ | (103 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| Income Statement Location | | Gain (Loss) | | Gain (Loss) |
| Operating revenues | | $ | 39 | | | $ | 76 | | | $ | 238 | | | $ | 65 | |
| Purchased power and fuel | | 209 | | | (45) | | | 224 | | | (127) | |
| Total Exelon and Generation | | $ | 248 | | | $ | 31 | | | $ | 462 | | | $ | (62) | |
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 September 30, 2019,2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 96%-99%, 84%-87%97%-100% and 54%-57%87%-90% for 2019, 2020 and 2021, respectively.
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 three and nine months ended September 30, 20192020 and 2018,2019, net pre-tax commodity mark-to-market gains (losses)and losses for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Derivative Financial Instruments
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 $1,371$1,217 million and $1,420$1,269 million at September 30, 20192020 and December 31, 2018,2019, respectively, for Exelon and $571$517 million and $620$569 million at September 30, 20192020 and December 31, 2018,2019, 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 $257$171 million and $268$231 million at September 30, 20192020 and December 31, 2018,2019, respectively.
The mark-to-market derivative assets and liabilities as of September 30, 20192020 and December 31, 20182019 and the mark-to-market gains and losses for the three and nine months ended September 30, 20192020 and 20182019 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Derivative Financial Instruments
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 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — 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 September 30, 2019.2020. 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 $68 million, $30 million, $32 million, $39 million, $15 million and $8 million as of September 30, 2019, respectively.
|
| | | | | | | | | | | | | | | | | | |
| Rating as of September 30, 2019 | 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 | $ | 693 |
| | $ | 10 |
| | $ | 683 |
| | — |
| | $ | — |
|
| Non-investment grade | 74 |
| | 38 |
| | 36 |
| |
|
| |
|
|
| No external ratings | | | | | | | | | |
| Internally rated — investment grade | 297 |
| | 1 |
| | 296 |
| |
|
| |
|
|
| Internally rated — non-investment grade | 175 |
| | 24 |
| | 151 |
| |
|
| |
|
|
| Total | $ | 1,239 |
| | $ | 73 |
| | $ | 1,166 |
| | — |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Rating as of September 30, 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 | | $ | 638 | | | $ | 27 | | | $ | 611 | | | 0 | | | $ | 0 | |
| Non-investment grade | | 4 | | | 0 | | | 4 | | | | | |
| No external ratings | | | | | | | | | | |
| Internally rated — investment grade | | 168 | | | 1 | | | 167 | | | | | |
| Internally rated — non-investment grade | | 110 | | | 29 | | | 81 | | | | | |
| Total | | $ | 920 | | | $ | 57 | | | $ | 863 | | | 0 | | | $ | 0 | |
|
| | | | |
| Net Credit Exposure by Type of Counterparty | | As of
September 30, 2019 |
| Financial institutions | | $ | 1 |
|
| Investor-owned utilities, marketers, power producers | | 875 |
|
| Energy cooperatives and municipalities | | 255 |
|
| Other | | 35 |
|
| Total | | $ | 1,166 |
|
_________
| | | | | | | | |
(a)Net Credit Exposure by Type of Counterparty | | As of September 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $18 million of cash2020 |
| Financial institutions | | $ | 26 | |
| Investor-owned utilities, marketers, power producers | | 650 | |
Energy cooperatives and $55 million of letters of credit. The credit collateral does not include non-liquid collateral.municipalities | | 142 | |
| Other | | 45 | |
| Total | | $ | 863 | |
_________
(a)As of September 30, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $26 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 September 30, 2019,2020, the Utility Registrants’ counterparty credit risk with suppliers was immaterial.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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Derivative Financial Instruments
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 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — 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:
| | | Credit-Risk Related Contingent Features | | September 30, 2019 | | December 31, 2018 | Credit-Risk Related Contingent Features | | September 30, 2020 | | December 31, 2019 |
Gross fair value of derivative contracts containing this feature(a) | | $ | (1,249 | ) | | $ | (1,723 | ) | Gross fair value of derivative contracts containing this feature(a) | | $ | (750) | | | $ | (956) | |
Offsetting fair value of in-the-money contracts under master netting arrangements(b) | | 947 |
| | 1,105 |
| Offsetting fair value of in-the-money contracts under master netting arrangements(b) | | 535 | | | 649 | |
Net fair value of derivative contracts containing this feature(c) | | $ | (302 | ) | | $ | (618 | ) | Net fair value of derivative contracts containing this feature(c) | | $ | (215) | | | $ | (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 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. |
(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 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.
As of September 30, 20192020 and December 31, 2018,2019, 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.
|
| | | | | | | | |
| | | September 30, 2019 | | December 31, 2018 |
| Cash collateral posted | | $ | 787 |
| | $ | 418 |
|
| Letters of credit posted | | 273 |
| | 367 |
|
| Cash collateral held | | 96 |
| | 47 |
|
| Letters of credit held | | 58 |
| | 44 |
|
| Additional collateral required in the event of a credit downgrade below investment grade | | 1,481 |
| | 2,104 |
|
| | | | | | | | | | | | | | |
| | September 30, 2020 | | December 31, 2019 |
| Cash collateral posted | | $ | 288 | | | $ | 982 | |
| Letters of credit posted | | 212 | | | 264 | |
| Cash collateral held | | 68 | | | 103 | |
| Letters of credit held | | 74 | | | 112 | |
| Additional collateral required in the event of a credit downgrade below investment grade | | 1,287 | | | 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 RegistrantsRate Reconciliation
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require themeffective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to post collateral.the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2020(a) | |
| | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO(b) | | BGE | | PHI(c) | | Pepco | | DPL | | ACE(c) | |
| 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 | 12.3 | | (10.3) | | 8.1 | | (6.2) | | 5.1 | | 5.5 | | 4.6 | | 6.6 | | 6.9 | |
| Qualified NDT fund income | 13.2 | | 47.4 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| | | | | | | | | | | | | | | | | | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.4) | | (4.5) | | (0.2) | | 0 | | (0.1) | | (0.2) | | (0.1) | | (0.2) | | (0.3) | |
| Plant basis differences | (4.3) | | 0 | | (0.6) | | (23.3) | | (1.2) | | (1.5) | | (2.1) | | (0.4) | | (1.3) | |
| Production tax credits and other credits | (3.0) | | (9.2) | | (0.4) | | 0 | | (0.8) | | (0.5) | | (0.5) | | (0.5) | | (0.4) | |
| Noncontrolling interests | 0.8 | | 2.9 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Excess deferred tax amortization | (10.1) | | 0 | | (5.6) | | (3.8) | | (10.6) | | (24.9) | | (20.0) | | (23.6) | | (36.8) | |
| Tax settlements | (0.2) | | (0.7) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Other | (0.8) | | (0.9) | | 1.1 | | (0.8) | | (0.3) | | 0.1 | | (0.4) | | 0.7 | | 0.6 | |
| Effective income tax rate | 27.5% | | 45.7% | | 23.4% | | (13.1)% | | 13.1% | | (0.5)% | | 2.5% | | 3.6% | | (10.3)% | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 109 — Derivative Financial InstrumentsIncome Taxes
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, and DPL’s credit rating. As of September 30, 2019, 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 ratings as of September 30, 2019, they could have been required to post incremental collateral to its counterparties of $28 million, $26 million and $11 million, respectively.
11. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 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 | 6.4 | | 5.2 | | 8.1 | | (0.3) | | 6.3 | | 4.8 | | 1.9 | | 6.6 | | 6.9 |
| Qualified NDT fund income | 3.2 | | 7.1 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Amortization of investment tax credit, including deferred taxes on basis difference | (4.1) | | (8.9) | | (0.2) | | 0 | | (0.1) | | (0.2) | | (0.1) | | (0.2) | | (0.3) |
| Plant basis differences | (1.7) | | 0 | | (1.0) | | (7.5) | | (1.1) | | (1.8) | | (2.6) | | (0.6) | | (1.9) |
| Production tax credits and other credits | (1.2) | | (2.7) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Noncontrolling interests | (2.2) | | (4.8) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Excess deferred tax amortization | (6.5) | | 0 | | (9.9) | | (3.6) | | (8.0) | | (17.7) | | (16.3) | | (13.5) | | (23.3) |
| Other | 0.7 | | 0.5 | | 0.4 | | (0.5) | | (0.2) | | 0.8 | | 1.0 | | (0.1) | | 0.7 |
| Effective income tax rate | 15.6% | | 17.4% | | 18.4% | | 9.1% | | 17.9% | | 6.9% | | 4.9% | | 13.2% | | 3.1% |
Exelon Corporate, ComEd, BGE, Pepco, DPL and ACE 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. 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.
Commercial Paper
The following table reflects the Registrants' commercial paper programs as of September 30, 2019 and December 31, 2018. Generation and PECO had no commercial paper borrowings as of both September 30, 2019 and December 31, 2018. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020(a) | |
| | | | | | | | | | | | | | | | | | |
| Exelon | | Generation(d) | | ComEd(e) | | PECO(b) | | BGE(c) | | PHI(c) | | Pepco(c) | | DPL(c) | | ACE(c) | |
| 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 | 9.3 | | 0 | | 12.7 | | (3.4) | | 5.5 | | 5.0 | | 4.2 | | 6.5 | | 6.8 | |
| Qualified NDT fund income | 3.2 | | 10.0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Deferred Prosecution Agreement payments | 2.5 | | 0 | | 9.4 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.2) | | (3.2) | | (0.3) | | 0 | | (0.1) | | (0.2) | | (0.1) | | (0.3) | | (0.5) | |
| Plant basis differences | (4.0) | | 0 | | (0.9) | | (15.9) | | (1.8) | | (2.2) | | (2.4) | | (0.5) | | (3.7) | |
| Production tax credits and other credits | (2.6) | | (7.0) | | (0.4) | | 0 | | (0.4) | | (0.3) | | (0.3) | | (0.2) | | (0.4) | |
| Noncontrolling interests | 1.0 | | 3.1 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Excess deferred tax amortization | (15.8) | | 0 | | (11.8) | | (3.5) | | (15.0) | | (45.3) | | (29.2) | | (53.6) | | (81.4) | |
| Tax settlements | (5.0) | | (15.7) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Other | 0.1 | | (0.5) | | 2.1 | | (0.5) | | (0.5) | | (0.6) | | (0.8) | | (1.1) | | 0 | |
| Effective income tax rate | 8.5% | | 7.7% | | 31.8% | | (2.3)% | | 8.7% | | (22.6)% | | (7.6)% | | (28.2)% | | (58.2)% | |
|
| | | | | | | | | | | | | |
| | Outstanding Commercial
Paper as of | | Average Interest Rate on
Commercial Paper Borrowings as of |
| Commercial Paper Issuer | September 30, 2019 | | December 31, 2018 | | September 30, 2019 | | December 31, 2018 |
| Exelon | $ | 519 |
| | $ | 89 |
| | 2.50 | % | | 2.15 | % |
| ComEd | 387 |
| | — |
| | 2.51 | % | | 2.14 | % |
| BGE | — |
| | 35 |
| | 2.49 | % | | 2.18 | % |
| PHI | 132 |
| | 54 |
| | 2.52 | % | | 2.15 | % |
| PEPCO | 12 |
| | 40 |
| | 2.61 | % | | 2.24 | % |
| DPL | 57 |
| | — |
| | 2.42 | % | | 2.07 | % |
| ACE | 63 |
| | 14 |
| | 2.57 | % | | 2.21 | % |
94
See Note 13— Debt and Credit Agreements of the Exelon 2018 Form 10-K for additional information on the Registrants’ credit facilities.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million, which was renewed on March 22, 2018 with an expiration of March 21, 2019. The loan agreement was renewed on March 20, 2019 and will expire on March 19, 2020. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-Term borrowings.
Credit Agreements
On February 21, 2019, Generation entered into a credit agreement establishing a $100 million bilateral credit facility. The facility will mature in March 2021. This facility will solely be used by Generation to issue letters of credit.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Debt and Credit Agreements
Long-Term Debt
Issuance of Long-Term Debt
During the nine months ended September 30, 2019, the following long-term debt was issued:
|
| | | | | | | | | | | | | |
| Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds |
| Generation | | Energy Efficiency Project Financing | | 3.95 | % | | August 31, 2020 | | $ | 4 |
| | Funding to install energy conservation measures for the Fort Meade project. |
| Generation | | Energy Efficiency Project Financing | | 3.46 | % | | May 1, 2020 | | $ | 39 |
| | Funding to install energy conservation measures for the Marine Corps. Logistics Project. |
| 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. |
| PECO | | First and Refunding Mortgage Bonds | | 3.00 | % | | September 15, 2049 | | $ | 325 |
| | Repay short-term borrowings and for general corporate purposes |
| BGE | | Senior Notes | | 3.20 | % | | September 15, 2049 | | $ | 400 |
| | Repay commercial paper obligations and for general corporate purposes |
| Pepco | | First Mortgage Bonds | | 3.45 | % | | June 13, 2029 | | $ | 150 |
| | Repay existing indebtedness and for general corporate purposes |
| Pepco | | Unsecured Tax-Exempt Bonds | | 1.70 | % | | September 1, 2022 | | $ | 110 |
| | Refinance existing indebtedness |
| ACE | | First Mortgage Bonds | | 3.50 | % | | May 21, 2029 | | $ | 100 |
| | Repay existing indebtedness and for general corporate purposes |
| ACE | | First Mortgage Bonds | | 4.14 | % | | May 21, 2049 | | $ | 50 |
| | Repay existing indebtedness and for general corporate purposes |
Debt CovenantsNote 9 — Income Taxes
As of September 30, 2019, the Registrants are in compliance with debt covenants, except for Antelope Valley's nonrecourse debt event of default as discussed below.
Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing. 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.
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. As of September 30, 2019, approximately $495 million was outstanding. 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.
Antelope Valley sells all
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 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 | 5.1 | | 4.2 | | 8.2 | | 0 | | 6.4 | | 4.8 | | 2.0 | | 6.7 | | 6.9 |
| Qualified NDT fund income | 5.3 | | 11.9 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.9) | | (4.0) | | (0.2) | | 0 | | (0.1) | | (0.2) | | (0.1) | | (0.2) | | (0.3) |
| Plant basis differences | (1.6) | | 0 | | (0.7) | | (6.8) | | (1.1) | | (1.8) | | (2.3) | | (0.6) | | (2.0) |
| Production tax credits and other credits | (1.0) | | (2.1) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Noncontrolling interests | (1.0) | | (2.3) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Excess deferred tax amortization | (6.0) | | 0 | | (9.2) | | (2.9) | | (7.9) | | (18.6) | | (17.3) | | (15.0) | | (23.4) |
| Other | 0.8 | | (0.1) | | 0.2 | | (0.2) | | 0.1 | | 0.5 | | 0.7 | | 0.2 | | 0 |
| Effective income tax rate | 20.7% | | 28.6% | | 19.3% | | 11.1% | | 18.4% | | 5.7% | | 4.0% | | 12.1% | | 2.2% |
__________
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)At PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to storm repairs.
(c)At BGE, PHI, Pepco, DPL, and ACE, the lower effective tax rate is primarily attributable to accelerated amortization 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 provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. Astransmission related deferred income tax regulatory liabilities as a result of the ongoing event of default and 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 and continues to be classified as current as of September 30, 2019. Further, distributions from Antelope Valley to EGR IV are currently suspended.regulatory settlements. See Note 2 — Regulatory Matters for additional information.
ExGen Renewables IV. (d)In November 2017, EGR IV, an indirect subsidiary of Exelon andAt 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 contributedthe lower effective tax rate is primarily attributable to and are pledged as collateral for thistax settlements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 9 — Income Taxes
Accounting for Uncertainty in Income Taxes
Exelon, Generation, PHI, and ACE have the following unrecognized tax benefits as of September 30, 2020 and December 31, 2019. ComEd, PECO, BGE, Pepco, and DPL's amounts are not material.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | | | PHI | | ACE |
| September 30, 2020 | $ | 125 | | | $ | 49 | | | | | $ | 53 | | | $ | 16 | |
| December 31, 2019 | 507 | | | 441 | | | | | 48 | | | 14 | |
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.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
The following table represents Exelon's, PHI's, and ACE's 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 as of September 30, 2020. Generation's, ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.
| | | | | | | | | | | | | | |
| Exelon | | PHI | | ACE(a) |
| $ | 14 | | | $ | 14 | | | $ | 14 | |
__________
(a)The unrecognized tax benefit related to ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Other Income Tax Matters
State Income Tax Law Changes
On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of state constitutional amendments in November 2020. The effect of the rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation, and ComEd do not expect a material impact to their financial statements as a result of the rate change.
Long-Term Marginal State Income Tax Rate (All Registrants)
In the third quarter of 2020 and 2019, Exelon updated its marginal state income tax rates for changes in state apportionment. The changes in marginal rates in the third quarter of 2020 resulted in an increase of $66 million and a decrease of $26 million to the deferred income tax liability at Exelon and Generation, respectively, as of September 30, 2020. The changes in marginal rates in the third quarter of 2019 resulted in an increase of $23 million and $9 million to the deferred income tax liability at Exelon and Generation, respectively, as of September 30, 2019. Exelon and Generation recorded a corresponding adjustment to income tax expense, net of federal taxes, in each of those respective periods.
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 benefit 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 federal tax benefits 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 9 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| September 30, 2020 | $ | 64 | | | $ | 14 | | | $ | 17 | | | $ | 0 | | | $ | 17 | | | $ | 8 | | | $ | 6 | | | $ | 1 | |
| December 31, 2019 | 41 | | | 0 | | | 14 | | | 3 | | | 7 | | | 6 | | | 1 | | | 0 | |
10. Retirement Benefits (All Registrants)
Defined Benefit Pension and OPEB
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.
The majority of the 2020 pension benefit cost for 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 three and nine months ended September 30, 2020 and 2019.
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Pension Benefits | | OPEB |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| Components of net periodic benefit cost: | | | | | | | |
| Service cost | $ | 97 | | | $ | 89 | | | $ | 22 | | | $ | 23 | |
| Interest cost | 190 | | | 221 | | | 37 | | | 47 | |
| Expected return on assets | (317) | | | (306) | | | (41) | | | (38) | |
| Amortization of: | | | | | | | |
| Prior service cost (benefit) | 1 | | | 0 | | | (30) | | | (45) | |
| Actuarial loss | 128 | | | 104 | | | 12 | | | 11 | |
| Settlement charges | 8 | | | 7 | | | 0 | | | 0 | |
| Contractual termination benefits | 0 | | | 1 | | | 0 | | | 0 | |
| Net periodic benefit cost | $ | 107 | | | $ | 116 | | | $ | 0 | | | $ | (2) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Pension Benefits | | OPEB |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
| Components of net periodic benefit cost: | | | | | | | |
| Service cost | $ | 290 | | | $ | 267 | | | $ | 67 | | | $ | 70 | |
| Interest cost | 569 | | | 663 | | | 114 | | | 141 | |
| Expected return on assets | (953) | | | (918) | | | (122) | | | (115) | |
| Amortization of: | | | | | | | |
| Prior service cost (benefit) | 3 | | | 0 | | | (92) | | | (134) | |
| Actuarial loss | 384 | | | 310 | | | 36 | | | 34 | |
| Settlement charges | 14 | | | 7 | | | 0 | | | 0 | |
| Contractual termination benefits | 0 | | | 1 | | | 0 | | | 0 | |
| Net periodic benefit cost | $ | 307 | | | $ | 330 | | | $ | 3 | | | $ | (4) | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 10 — Retirement Benefits
The amounts below represent the Registrants' allocated pension and OPEB plan 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Pension and OPEB Costs | | 2020 | | 2019 | | 2020 | | 2019 |
| Exelon | | $ | 107 | | | $ | 114 | | | $ | 310 | | | $ | 326 | |
| Generation | | 30 | | | 37 | | | 89 | | | 100 | |
| ComEd | | 29 | | | 23 | | | 85 | | | 70 | |
| PECO | | 1 | | | 4 | | | 4 | | | 9 | |
| BGE | | 16 | | | 16 | | | 47 | | | 47 | |
| PHI | | 17 | | | 23 | | | 52 | | | 71 | |
| Pepco | | 4 | | | 6 | | | 11 | | | 19 | |
| DPL | | 2 | | | 4 | | | 6 | | | 11 | |
| ACE | | 3 | | | 4 | | | 10 | | | 12 | |
Defined Contribution Savings Plans
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 the matching contributions to the savings plans during the three and nine months ended September 30, 2020 and 2019, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Savings Plan Matching Contributions | | 2020 | | 2019 | | 2020 | | 2019 |
| Exelon | | $ | 37 | | | $ | 36 | | | $ | 104 | | | $ | 101 | |
| Generation | | 14 | | | 14 | | | 41 | | | 41 | |
| ComEd | | 9 | | | 9 | | | 25 | | | 26 | |
| PECO | | 3 | | | 2 | | | 8 | | | 7 | |
| BGE | | 4 | | | 4 | | | 8 | | | 9 | |
| PHI | | 3 | | | 4 | | | 9 | | | 8 | |
| Pepco | | 1 | | | 1 | | | 3 | | | 2 | |
| DPL | | 1 | | | 1 | | | 2 | | | 2 | |
| ACE | | 0 | | | 1 | | | 1 | | | 1 | |
11. 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — DebtDerivative Financial Instruments
Authoritative guidance about offsetting assets and Credit Agreementsliabilities 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 referencing 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 that 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.
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Derivative Financial Instruments
financing. | | | | | | | | | | | |
| 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 15% 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 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 of the 2019 Form 10-K 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 loanfair value of the DPL economic hedge is schedulednot material as of September 30, 2020 and December 31, 2019 and is not presented in the fair value tables below.
The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of September 30, 2020 and December 31, 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2020 | | Exelon | | Generation | | ComEd | | | | |
| Derivatives | | Total
Derivatives | | Economic
Hedges | | Proprietary
Trading | | Collateral(a)(b) | | Netting(a) | | Subtotal | | Economic
Hedges | | | | | | | | |
Mark-to-market derivative assets
(current assets) | | $ | 471 | | | $ | 2,566 | | | $ | 58 | | | $ | 79 | | | $ | (2,232) | | | $ | 471 | | | $ | 0 | | | | | | | | | |
Mark-to-market derivative assets
(noncurrent assets) | | 383 | | | 1,500 | | | 16 | | | 39 | | | (1,172) | | | 383 | | | 0 | | | | | | | | | |
| Total mark-to-market derivative assets | | 854 | | | 4,066 | | | 74 | | | 118 | | | (3,404) | | | 854 | | | 0 | | | | | | | | | |
Mark-to-market derivative liabilities
(current liabilities) | | (168) | | | (2,414) | | | (40) | | | 84 | | | 2,232 | | | (138) | | | (30) | | | | | | | | | |
Mark-to-market derivative liabilities
(noncurrent liabilities) | | (378) | | | (1,313) | | | (12) | | | 49 | | | 1,172 | | | (104) | | | (274) | | | | | | | | | |
| Total mark-to-market derivative liabilities | | (546) | | | (3,727) | | | (52) | | | 133 | | | 3,404 | | | (242) | | | (304) | | | | | | | | | |
| Total mark-to-market derivative net assets (liabilities) | | $ | 308 | | | $ | 339 | | | $ | 22 | | | $ | 251 | | | $ | 0 | | | $ | 612 | | | $ | (304) | | | | | | | | | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Derivative Financial Instruments
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2019 | | Exelon | | Generation | | ComEd | | | | |
| Description | | Total
Derivatives | | Economic
Hedges | | Proprietary
Trading | | Collateral(a)(b) | | Netting(a) | | Subtotal | | Economic
Hedges | | | | | | | | |
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 maturea 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/(received), $34 million and $511 million represents variation margin on November 28, 2024.the exchanges at September 30, 2020 and December 31, 2019 respectively.
Economic Hedges (Commodity Price Risk)
Generation. For the three and nine months ended September 30, 2020 and 2019, 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| Income Statement Location | | Gain (Loss) | | Gain (Loss) |
| Operating revenues | | $ | 39 | | | $ | 76 | | | $ | 238 | | | $ | 65 | |
| Purchased power and fuel | | 209 | | | (45) | | | 224 | | | (127) | |
| Total Exelon and Generation | | $ | 248 | | | $ | 31 | | | $ | 462 | | | $ | (62) | |
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 September 30, 2019, $796 million was outstanding.2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 97%-100% and 87%-90% for 2020 and 2021, respectively.
Although Antelope Valley’s debt isProprietary 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 default, it is nonrecoursemarket prices as opposed to EGR IV. However, ifthose 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 future Antelope ValleyNet fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the three and nine months ended September 30, 2020 and 2019, 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Derivative Financial Instruments
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 $1,217 million and $1,269 million at September 30, 2020 and December 31, 2019, respectively, for Exelon and $517 million and $569 million at September 30, 2020 and December 31, 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 $171 million and $231 million at September 30, 2020 and December 31, 2019, respectively.
The mark-to-market derivative assets and liabilities as of September 30, 2020 and December 31, 2019 and the mark-to-market gains and losses for the three and nine months ended September 30, 2020 and 2019 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 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — 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 September 30, 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 September 30, 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 | | $ | 638 | | | $ | 27 | | | $ | 611 | | | 0 | | | $ | 0 | |
| Non-investment grade | | 4 | | | 0 | | | 4 | | | | | |
| No external ratings | | | | | | | | | | |
| Internally rated — investment grade | | 168 | | | 1 | | | 167 | | | | | |
| Internally rated — non-investment grade | | 110 | | | 29 | | | 81 | | | | | |
| Total | | $ | 920 | | | $ | 57 | | | $ | 863 | | | 0 | | | $ | 0 | |
| | | | | | | | |
| Net Credit Exposure by Type of Counterparty | | As of September 30, 2020 |
| Financial institutions | | $ | 26 | |
| Investor-owned utilities, marketers, power producers | | 650 | |
| Energy cooperatives and municipalities | | 142 | |
| Other | | 45 | |
| Total | | $ | 863 | |
_________
(a)As of September 30, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $26 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 September 30, 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 filebe 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 bankruptcy protection asthe 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 result of events culminating from PG&E’s bankruptcy proceedings this would represent an event of default for EGR IV’s debt that would provide the lender with an opportunity to accelerate EGR IV’s debt.
See Note 13— Debt and Credit Agreementsfunction of the Exelon 2018 Form 10-Kfacts 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 additional information on nonrecourse debt.the contingent collateral obligation, which has been factored into the disclosure below.
103
12. Income Taxes (All Registrants)
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — 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:
| | | | | | | | | | | | | | |
| Credit-Risk Related Contingent Features | | September 30, 2020 | | December 31, 2019 |
Gross fair value of derivative contracts containing this feature(a) | | $ | (750) | | | $ | (956) | |
Offsetting fair value of in-the-money contracts under master netting arrangements(b) | | 535 | | | 649 | |
Net fair value of derivative contracts containing this feature(c) | | $ | (215) | | | $ | (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 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.
As of September 30, 2020 and December 31, 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.
| | | | | | | | | | | | | | |
| | September 30, 2020 | | December 31, 2019 |
| Cash collateral posted | | $ | 288 | | | $ | 982 | |
| Letters of credit posted | | 212 | | | 264 | |
| Cash collateral held | | 68 | | | 103 | |
| Letters of credit held | | 74 | | | 112 | |
| Additional collateral required in the event of a credit downgrade below investment grade | | 1,287 | | | 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.
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. Federalfederal statutory rate principally due to the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2020(a) | |
| | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO(b) | | BGE | | PHI(c) | | Pepco | | DPL | | ACE(c) | |
| 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 | 12.3 | | (10.3) | | 8.1 | | (6.2) | | 5.1 | | 5.5 | | 4.6 | | 6.6 | | 6.9 | |
| Qualified NDT fund income | 13.2 | | 47.4 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| | | | | | | | | | | | | | | | | | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.4) | | (4.5) | | (0.2) | | 0 | | (0.1) | | (0.2) | | (0.1) | | (0.2) | | (0.3) | |
| Plant basis differences | (4.3) | | 0 | | (0.6) | | (23.3) | | (1.2) | | (1.5) | | (2.1) | | (0.4) | | (1.3) | |
| Production tax credits and other credits | (3.0) | | (9.2) | | (0.4) | | 0 | | (0.8) | | (0.5) | | (0.5) | | (0.5) | | (0.4) | |
| Noncontrolling interests | 0.8 | | 2.9 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Excess deferred tax amortization | (10.1) | | 0 | | (5.6) | | (3.8) | | (10.6) | | (24.9) | | (20.0) | | (23.6) | | (36.8) | |
| Tax settlements | (0.2) | | (0.7) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Other | (0.8) | | (0.9) | | 1.1 | | (0.8) | | (0.3) | | 0.1 | | (0.4) | | 0.7 | | 0.6 | |
| Effective income tax rate | 27.5% | | 45.7% | | 23.4% | | (13.1)% | | 13.1% | | (0.5)% | | 2.5% | | 3.6% | | (10.3)% | |
|
| | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2019 |
| | 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 | 6.4 | | 5.2 | | 8.1 | | (0.3) | | 6.3 | | 4.8 | | 1.9 | | 6.6 | | 6.9 |
| Qualified NDT fund income | 3.2 | | 7.1 | | — | | — | | — | | — | | — | | — | | — |
| Amortization of investment tax credit, including deferred taxes on basis difference | (4.1) | | (8.9) | | (0.2) | | — | | (0.1) | | (0.2) | | (0.1) | | (0.2) | | (0.3) |
| Plant basis differences | (1.7) | | — | | (1.0) | | (7.5) | | (1.1) | | (1.8) | | (2.6) | | (0.6) | | (1.9) |
| Production tax credits and other credits | (1.2) | | (2.7) | | — | | — | | — | | — | | — | | — | | — |
| Noncontrolling interests | (2.2) | | (4.8) | | — | | — | | — | | — | | — | | — | | — |
| Excess deferred tax amortization | (6.5) | | — | | (9.9) | | (3.6) | | (8.0) | | (17.7) | | (16.3) | | (13.5) | | (23.3) |
| Other | 0.7 | | 0.5 | | 0.4 | | (0.5) | | (0.2) | | 0.8 | | 1.0 | | (0.1) | | 0.7 |
| Effective income tax rate | 15.6% | | 17.4% | | 18.4% | | 9.1% | | 17.9% | | 6.9% | | 4.9% | | 13.2% | | 3.1% |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 129 — Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 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 | 6.4 | | 5.2 | | 8.1 | | (0.3) | | 6.3 | | 4.8 | | 1.9 | | 6.6 | | 6.9 |
| Qualified NDT fund income | 3.2 | | 7.1 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Amortization of investment tax credit, including deferred taxes on basis difference | (4.1) | | (8.9) | | (0.2) | | 0 | | (0.1) | | (0.2) | | (0.1) | | (0.2) | | (0.3) |
| Plant basis differences | (1.7) | | 0 | | (1.0) | | (7.5) | | (1.1) | | (1.8) | | (2.6) | | (0.6) | | (1.9) |
| Production tax credits and other credits | (1.2) | | (2.7) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Noncontrolling interests | (2.2) | | (4.8) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Excess deferred tax amortization | (6.5) | | 0 | | (9.9) | | (3.6) | | (8.0) | | (17.7) | | (16.3) | | (13.5) | | (23.3) |
| Other | 0.7 | | 0.5 | | 0.4 | | (0.5) | | (0.2) | | 0.8 | | 1.0 | | (0.1) | | 0.7 |
| Effective income tax rate | 15.6% | | 17.4% | | 18.4% | | 9.1% | | 17.9% | | 6.9% | | 4.9% | | 13.2% | | 3.1% |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020(a) | |
| | | | | | | | | | | | | | | | | | |
| Exelon | | Generation(d) | | ComEd(e) | | PECO(b) | | BGE(c) | | PHI(c) | | Pepco(c) | | DPL(c) | | ACE(c) | |
| 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 | 9.3 | | 0 | | 12.7 | | (3.4) | | 5.5 | | 5.0 | | 4.2 | | 6.5 | | 6.8 | |
| Qualified NDT fund income | 3.2 | | 10.0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Deferred Prosecution Agreement payments | 2.5 | | 0 | | 9.4 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.2) | | (3.2) | | (0.3) | | 0 | | (0.1) | | (0.2) | | (0.1) | | (0.3) | | (0.5) | |
| Plant basis differences | (4.0) | | 0 | | (0.9) | | (15.9) | | (1.8) | | (2.2) | | (2.4) | | (0.5) | | (3.7) | |
| Production tax credits and other credits | (2.6) | | (7.0) | | (0.4) | | 0 | | (0.4) | | (0.3) | | (0.3) | | (0.2) | | (0.4) | |
| Noncontrolling interests | 1.0 | | 3.1 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Excess deferred tax amortization | (15.8) | | 0 | | (11.8) | | (3.5) | | (15.0) | | (45.3) | | (29.2) | | (53.6) | | (81.4) | |
| Tax settlements | (5.0) | | (15.7) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | |
| Other | 0.1 | | (0.5) | | 2.1 | | (0.5) | | (0.5) | | (0.6) | | (0.8) | | (1.1) | | 0 | |
| Effective income tax rate | 8.5% | | 7.7% | | 31.8% | | (2.3)% | | 8.7% | | (22.6)% | | (7.6)% | | (28.2)% | | (58.2)% | |
|
| | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2018 |
| | 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 | (1.2) | | (9.0) | | 8.3 | | (3.6) | | 7.3 | | 0.2 | | 1.0 | | 6.6 | | 7.3 |
| Qualified NDT fund income | 2.4 | | 5.8 | | — | | — | | — | | — | | — | | — | | — |
| Amortization of investment tax credit, including deferred taxes on basis difference | (0.6) | | (1.1) | | (0.2) | | (0.1) | | — | | (0.2) | | (0.1) | | (0.3) | | (0.3) |
| Plant basis differences | (2.5) | | — | | (0.3) | | (15.2) | | (0.8) | | (2.0) | | (3.4) | | (0.7) | | (1.3) |
| Production tax credits and other credits | (1.2) | | (2.9) | | (0.1) | | — | | — | | — | | — | | — | | — |
| Noncontrolling interests | (1.1) | | (2.8) | | — | | — | | — | | — | | — | | — | | — |
| Excess deferred tax amortization | (6.8) | | — | | (7.8) | | (4.6) | | (7.9) | | (17.7) | | (21.2) | | (14.0) | | (15.4) |
| Tax Cuts and Jobs Act of 2017 | 1.3 | | 3.5 | | — | | — | | — | | 0.2 | | 0.1 | | — | | — |
| Other | 3.2 | | 5.6 | | 0.3 | | 0.9 | | 2.6 | | 0.6 | | 0.3 | | 0.6 | | 0.3 |
| Effective income tax rate | 14.5% | | 20.1% | | 21.2% | | (1.6)% | | 22.2% | | 2.1% | | (2.3)% | | 13.2% | | 11.6% |
94
|
| | | | | | | | | | | | | | | | | |
| | |
| | Nine Months Ended September 30, 2019 |
| | 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 | 5.1 | | 4.2 | | 8.2 | | — | | 6.4 | | 4.8 | | 2.0 | | 6.7 | | 6.9 |
| Qualified NDT fund income | 5.3 | | 11.9 | | — | | — | | — | | — | | — | | — | | — |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.9) | | (4.0) | | (0.2) | | — | | (0.1) | | (0.2) | | (0.1) | | (0.2) | | (0.3) |
| Plant basis differences | (1.6) | | — | | (0.7) | | (6.8) | | (1.1) | | (1.8) | | (2.3) | | (0.6) | | (2.0) |
| Production tax credits and other credits | (1.0) | | (2.1) | | — | | — | | — | | — | | — | | — | | — |
| Noncontrolling interests | (1.0) | | (2.3) | | — | | — | | — | | — | | — | | — | | — |
| Excess deferred tax amortization | (6.0) | | — | | (9.2) | | (2.9) | | (7.9) | | (18.6) | | (17.3) | | (15.0) | | (23.4) |
| Other | 0.8 | | (0.1) | | 0.2 | | (0.2) | | 0.1 | | 0.5 | | 0.7 | | 0.2 | | — |
| Effective income tax rate | 20.7% | | 28.6% | | 19.3% | | 11.1% | | 18.4% | | 5.7% | | 4.0% | | 12.1% | | 2.2% |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 129 — Income Taxes
|
| | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2018 |
| | 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 | 1.7 | | (2.6) | | 8.2 | | (3.6) | | 6.6 | | 2.7 | | 2.4 | | 6.5 | | 7.3 |
| Qualified NDT fund income | 0.9 | | 2.6 | | — | | — | | — | | — | | — | | — | | — |
| Amortization of investment tax credit, including deferred taxes on basis difference | (0.9) | | (2.2) | | (0.2) | | (0.1) | | (0.1) | | (0.2) | | (0.1) | | (0.3) | | (0.3) |
| Plant basis differences | (2.7) | | — | | (0.1) | | (15.4) | | (0.7) | | (1.9) | | (2.9) | | (0.7) | | (1.3) |
| Production tax credits and other credits | (1.8) | | (5.1) | | (0.1) | | — | | — | | — | | — | | — | | — |
| Noncontrolling interests | (1.1) | | (3.2) | | — | | — | | — | | — | | — | | — | | — |
| Excess deferred tax amortization | (6.1) | | — | | (7.6) | | (3.4) | | (8.1) | | (14.5) | | (16.5) | | (11.0) | | (14.0) |
| Tax Cuts and Jobs Act of 2017 | 0.2 | | 1.3 | | (0.2) | | — | | — | | 0.3 | | — | | — | | — |
| Other | 0.4 | | 2.0 | | 0.1 | | — | | 0.9 | | 0.3 | | — | | 0.4 | | 0.9 |
| Effective income tax rate | 11.6% | | 13.8% | | 21.1% | | (1.5)% | | 19.6% | | 7.7% | | 3.9% | | 15.9% | | 13.6% |
Accounting for Uncertainty
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 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 | 5.1 | | 4.2 | | 8.2 | | 0 | | 6.4 | | 4.8 | | 2.0 | | 6.7 | | 6.9 |
| Qualified NDT fund income | 5.3 | | 11.9 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Amortization of investment tax credit, including deferred taxes on basis difference | (1.9) | | (4.0) | | (0.2) | | 0 | | (0.1) | | (0.2) | | (0.1) | | (0.2) | | (0.3) |
| Plant basis differences | (1.6) | | 0 | | (0.7) | | (6.8) | | (1.1) | | (1.8) | | (2.3) | | (0.6) | | (2.0) |
| Production tax credits and other credits | (1.0) | | (2.1) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Noncontrolling interests | (1.0) | | (2.3) | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 | | 0 |
| Excess deferred tax amortization | (6.0) | | 0 | | (9.2) | | (2.9) | | (7.9) | | (18.6) | | (17.3) | | (15.0) | | (23.4) |
| Other | 0.8 | | (0.1) | | 0.2 | | (0.2) | | 0.1 | | 0.5 | | 0.7 | | 0.2 | | 0 |
| Effective income tax rate | 20.7% | | 28.6% | | 19.3% | | 11.1% | | 18.4% | | 5.7% | | 4.0% | | 12.1% | | 2.2% |
__________
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)At PECO, the lower effective tax rate is primarily related to an increase in Income Taxesplant basis differences attributable to storm repairs.
Exelon, Generation, ComEd,(c)At BGE, PHI, Pepco, DPL, and ACE, have the following unrecognizedlower effective tax benefitsrate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of September 30, 2019 and December 31, 2018. PECO, BGE, Pepco and DPL do not have unrecognizedregulatory settlements. See Note 2 — Regulatory Matters for additional information.
(d)At Generation, the lower effective tax benefits forrate is primarily attributable to tax settlements.
(e)At ComEd, the periods presented.
|
| | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PHI | | ACE |
| September 30, 2019 | $ | 448 |
| | $ | 411 |
| | $ | — |
| | $ | 45 |
| | $ | 14 |
|
| December 31, 2018 | $ | 477 |
| | $ | 408 |
| | $ | 2 |
| | $ | 45 |
| | $ | 14 |
|
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 thehigher effective tax and interestrate is primarily related to the gain deferral, the Tax Court also ruled that Exelon was liablenondeductible Deferred Prosecution Agreement payments. See Note 14 — Commitments and Contingencies 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 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 129 — Income Taxes
Exelon, Generation, PHI, and ACE have the following unrecognized tax benefits as of September 30, 2020 and December 31, 2019. ComEd, PECO, BGE, Pepco, and DPL's amounts are not material.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | | | PHI | | ACE |
| September 30, 2020 | $ | 125 | | | $ | 49 | | | | | $ | 53 | | | $ | 16 | |
| December 31, 2019 | 507 | | | 441 | | | | | 48 | | | 14 | |
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.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
Settlement of Income Tax Audits, Refund Claims,The following table represents Exelon's, PHI's, and Litigation
Exelon, Generation, PHI and ACE have the followingACE's 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 as of September 30, 2019:2020. Generation's, ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.
| | Exelon(a) |
| Generation(a) |
| PHI(b) |
| ACE(b) | |
| Exelon | | Exelon | | PHI | | ACE(a) |
| $ | 425 |
|
| $ | 411 |
|
| $ | 14 |
|
| $ | 14 |
| 14 | | | $ | 14 | | | $ | 14 | |
__________
| |
(a) | Exelon and Generation have $411 million that, if recognized, would decrease the effective tax rate. |
| |
(b) | 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. |
(a)The unrecognized tax benefit related to ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Other Income Tax Matters
Marginal State Income Tax Rate (Exelon, Generation)
In the third quarter of 2019, Exelon reviewed and updated its marginal state income tax rates based on 2018 state apportionment rates. As a result of the rate changes, the following accounting adjustments were recorded as of September 30, 2019:
|
| | | | | | | | |
| | | Exelon | | Generation |
| Increase to deferred income tax liability | | $ | 23 |
| | $ | 9 |
|
| Increase to income tax expense, net of federal taxes | | 23 |
| | 9 |
|
State Income Tax Law Changes
On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of state constitutional amendments in November 2020. The effect of the rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation, and ComEd do not expect a material impact to their financial statements as a result of the rate change.
Long-Term Marginal State Income Tax Rate (All Registrants) 13. Nuclear Decommissioning (ExelonIn the third quarter of 2020 and Generation)
Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)
Generation has a legal obligation to decommission2019, Exelon updated 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 escalationmarginal state income tax 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.
The financial statement impact for changes in state apportionment. The changes in marginal rates in the ARO, onthird quarter of 2020 resulted in an individual unit basis, dueincrease of $66 million and a decrease of $26 million to the deferred income tax liability at Exelon and Generation, respectively, as of September 30, 2020. The changes in marginal rates in the third quarter of 2019 resulted in an increase of $23 million and timing$9 million to the deferred income tax liability at Exelon and Generation, respectively, as of estimated cash flows generally result inSeptember 30, 2019. Exelon and Generation recorded a corresponding changeadjustment to income tax expense, net of federal taxes, in each of those respective periods.
Allocation of Tax Benefits (All Registrants)
Generation and the unit’s ARC within Property, plantUtility Registrants are all party to an agreement with Exelon and equipment on Exelon’sother subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and Generation’s Consolidated Balance Sheets. Ifbenefits (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 ARO decreases forparty been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a Non-Regulatory Agreement unit without any remaining ARC,contribution to the corresponding change is recorded as decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statementscapital of Operations and Comprehensive Income.the party receiving the benefit.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 139 — Nuclear DecommissioningIncome Taxes
The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2018 to September 30, 2019:
|
| | | |
Nuclear decommissioning ARO at December 31, 2018 (a)(b) | $ | 10,005 |
|
| Sale of Oyster Creek | (755 | ) |
| Accretion expense | 361 |
|
| Net increase due to changes in, and timing of, estimated future cash flows | 211 |
|
| Costs incurred related to decommissioning plants | (52 | ) |
Nuclear decommissioning ARO at September 30, 2019 (a) | $ | 9,770 |
|
_________
| |
(a) | Includes $127 million and $22 million as the current portion of the ARO at September 30, 2019 and December 31, 2018, 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 was classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018. See Note 3 — Mergers, Acquisitions and Dispositions for additional information. |
During the nine months ended September 30, 2019, Exelon's and Generation’s total nuclear ARO decreased by approximately $235 million, primarily reflecting the sale of Oyster Creek, partially offset by the accretion of the ARO liability due to the passage of time and the net impacts of ARO updates completed during the first and third quarters of 2019.
The first quarter 2019 ARO update included an increase of approximately $330 million for a change in the assumed retirement timing probabilities for certain economically challenged nuclear plants and a $110 million decrease for the impacts of revised decommissioning cost estimates for TMI which incorporate site specific decommissioning planning activities associated with the early retirement of TMI on September 20, 2019. The TMI ARO adjustment resulted in an $85 million decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. See Note 8 — Early Plant Retirements for additional information.
The third quarter 2019 ARO update included a decrease of approximately $300 million due to lower estimated costs to decommission Nine Mile Point, Ginna, Braidwood, Byron and LaSalle nuclear units resulting from the completion of updated cost studies, partially offset by an increase of approximately $280 million for other impacts that included updated cost escalation rates, primarily for labor, equipment and materials, and current discount rates. The third quarter ARO adjustment resulted in a $65 million decrease in Operating and maintenance expense within Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income.
NDT Funds (Exelon and Generation)
Exelon and Generation had NDT funds totaling $12,862 million and $12,695 million at September 30, 2019 and December 31, 2018, respectively. The NDT funds included $890 million at December 31, 2018, related to Oyster Creek NDT funds which were classified as Assets held for sale in Exelon's and Generation's Consolidated Balance Sheets. See Note 3 — Mergers, Acquisitions and Dispositions for additional information regarding the sale of Oyster Creek. The NDT funds also include $156 million and $144 million for the current portion of the NDT funds at September 30, 2019 and December 31, 2018, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 17 — Supplemental Financial Information for additional information on activities of the NDT funds.
NRC Minimum Funding Requirements (Exelon and Generation)
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.
Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 for all 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
Table of Contents | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| September 30, 2020 | $ | 64 | | | $ | 14 | | | $ | 17 | | | $ | 0 | | | $ | 17 | | | $ | 8 | | | $ | 6 | | | $ | 1 | |
| December 31, 2019 | 41 | | | 0 | | | 14 | | | 3 | | | 7 | | | 6 | | | 1 | | | 0 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — Nuclear Decommissioning
April 1, 2019 submittal. 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. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for information regarding the amount collected from PECO ratepayers for decommissioning cost.
14.10. Retirement Benefits (All Registrants)
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 is not changing the benefits offered to the plan participants and, thus, has no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP are being amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan.
Defined Benefit Pension and OPEB
During the first quarter of 2019,2020, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2019.2020. This valuation resulted in an increase to the pension and OPEB obligations of $75$8 million and $36$31 million, respectively. Additionally, accumulated other comprehensive loss increased by $39$7 million (after-tax) and regulatory assets and liabilities increased by $53$19 million and decreased by $5$10 million, respectively.
The majority of the 20192020 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.31%3.34%. The majority of the 20192020 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.67%6.69% for funded plans and a discount rate of 4.30%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 three and nine months ended September 30, 20192020 and 2018.2019.
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Pension Benefits | | OPEB |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| Components of net periodic benefit cost: | | | | | | | |
| Service cost | $ | 97 | | | $ | 89 | | | $ | 22 | | | $ | 23 | |
| Interest cost | 190 | | | 221 | | | 37 | | | 47 | |
| Expected return on assets | (317) | | | (306) | | | (41) | | | (38) | |
| Amortization of: | | | | | | | |
| Prior service cost (benefit) | 1 | | | 0 | | | (30) | | | (45) | |
| Actuarial loss | 128 | | | 104 | | | 12 | | | 11 | |
| Settlement charges | 8 | | | 7 | | | 0 | | | 0 | |
| Contractual termination benefits | 0 | | | 1 | | | 0 | | | 0 | |
| Net periodic benefit cost | $ | 107 | | | $ | 116 | | | $ | 0 | | | $ | (2) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Pension Benefits | | OPEB |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
| Components of net periodic benefit cost: | | | | | | | |
| Service cost | $ | 290 | | | $ | 267 | | | $ | 67 | | | $ | 70 | |
| Interest cost | 569 | | | 663 | | | 114 | | | 141 | |
| Expected return on assets | (953) | | | (918) | | | (122) | | | (115) | |
| Amortization of: | | | | | | | |
| Prior service cost (benefit) | 3 | | | 0 | | | (92) | | | (134) | |
| Actuarial loss | 384 | | | 310 | | | 36 | | | 34 | |
| Settlement charges | 14 | | | 7 | | | 0 | | | 0 | |
| Contractual termination benefits | 0 | | | 1 | | | 0 | | | 0 | |
| Net periodic benefit cost | $ | 307 | | | $ | 330 | | | $ | 3 | | | $ | (4) | |
|
| | | | | | | | | | | | | | | |
| | Pension Benefits
Three Months Ended September 30, | | OPEB
Three Months Ended September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| Components of net periodic benefit cost: | | | | | | | |
| Service cost | $ | 89 |
| | $ | 100 |
| | $ | 23 |
| | $ | 28 |
|
| Interest cost | 221 |
| | 201 |
| | 47 |
| | 43 |
|
| Expected return on assets | (306 | ) | | (312 | ) | | (38 | ) | | (43 | ) |
| Amortization of: | | | | | | | |
| Prior service benefit | — |
| | — |
| | (45 | ) | | (47 | ) |
| Actuarial loss | 104 |
| | 158 |
| | 11 |
| | 18 |
|
| Settlement charges | 7 |
| | — |
| | — |
| | — |
|
| Contractual termination benefits | 1 |
| | — |
| | — |
| | — |
|
| Net periodic benefit cost | $ | 116 |
| | $ | 147 |
| | $ | (2 | ) | | $ | (1 | ) |
97
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1410 — Retirement Benefits
|
| | | | | | | | | | | | | | | |
| Pension Benefits
Nine Months Ended September 30, | | OPEB
Nine Months Ended September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| Components of net periodic benefit cost: |
|
| |
|
| |
|
| |
|
|
| Service cost | $ | 267 |
| | $ | 303 |
| | $ | 70 |
| | $ | 84 |
|
| Interest cost | 663 |
| | 602 |
| | 141 |
| | 131 |
|
| Expected return on assets | (918 | ) | | (939 | ) | | (115 | ) | | (130 | ) |
| Amortization of: | | | | | | | |
| Prior service cost (benefit) | — |
| | 1 |
| | (134 | ) | | (140 | ) |
| Actuarial loss | 310 |
| | 472 |
| | 34 |
| | 50 |
|
| Settlement charges | 7 |
| | 1 |
| | — |
| | — |
|
| Contractual termination benefits | 1 |
| | — |
| | — |
| | — |
|
| Net periodic benefit cost | $ | 330 |
|
| $ | 440 |
|
| $ | (4 | ) |
| $ | (5 | ) |
The amounts below represent the Registrants' allocated pension and OPEB plan 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.
| | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Pension and OPEB Costs | | 2019 | | 2018 | | 2019 | | 2018 | Pension and OPEB Costs | | 2020 | | 2019 | | 2020 | | 2019 |
| Exelon | | $ | 114 |
| | $ | 145 |
| | $ | 326 |
| | $ | 435 |
| Exelon | | $ | 107 | | | $ | 114 | | | $ | 310 | | | $ | 326 | |
| Generation | | 37 |
| | 50 |
| | 100 |
| | 151 |
| Generation | | 30 | | | 37 | | | 89 | | | 100 | |
| ComEd | | 23 |
| | 45 |
| | 70 |
| | 133 |
| ComEd | | 29 | | | 23 | | | 85 | | | 70 | |
| PECO | | 4 |
| | 5 |
| | 9 |
| | 14 |
| PECO | | 1 | | | 4 | | | 4 | | | 9 | |
| BGE | | 16 |
| | 15 |
| | 47 |
| | 44 |
| BGE | | 16 | | | 16 | | | 47 | | | 47 | |
| PHI | | 23 |
| | 17 |
| | 71 |
| | 51 |
| PHI | | 17 | | | 23 | | | 52 | | | 71 | |
| Pepco | | 6 |
| | 3 |
| | 19 |
| | 10 |
| Pepco | | 4 | | | 6 | | | 11 | | | 19 | |
| DPL | | 4 |
| | 2 |
| | 11 |
| | 5 |
| DPL | | 2 | | | 4 | | | 6 | | | 11 | |
| ACE | | 4 |
| | 3 |
| | 12 |
| | 10 |
| ACE | | 3 | | | 4 | | | 10 | | | 12 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Retirement Benefits
Defined Contribution Savings Plans
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 the matching contributions to the savings plans during the three and nine months ended September 30, 20192020 and 2018,2019, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Savings Plan Matching Contributions | | 2020 | | 2019 | | 2020 | | 2019 |
| Exelon | | $ | 37 | | | $ | 36 | | | $ | 104 | | | $ | 101 | |
| Generation | | 14 | | | 14 | | | 41 | | | 41 | |
| ComEd | | 9 | | | 9 | | | 25 | | | 26 | |
| PECO | | 3 | | | 2 | | | 8 | | | 7 | |
| BGE | | 4 | | | 4 | | | 8 | | | 9 | |
| PHI | | 3 | | | 4 | | | 9 | | | 8 | |
| Pepco | | 1 | | | 1 | | | 3 | | | 2 | |
| DPL | | 1 | | | 1 | | | 2 | | | 2 | |
| ACE | | 0 | | | 1 | | | 1 | | | 1 | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Savings Plan Matching Contributions | | 2019 | | 2018 | | 2019 | | 2018 |
| Exelon | | $ | 36 |
| | $ | 44 |
|
| $ | 101 |
|
| $ | 126 |
|
| Generation | | 14 |
| | 23 |
| | 41 |
| | 65 |
|
| ComEd | | 9 |
| | 8 |
| | 26 |
| | 23 |
|
| PECO | | 2 |
| | 2 |
| | 7 |
| | 7 |
|
| BGE | | 4 |
| | 2 |
| | 9 |
| | 5 |
|
| PHI | | 4 |
| | 4 |
| | 8 |
| | 10 |
|
| Pepco | | 1 |
| | 1 |
| | 2 |
| | 2 |
|
| DPL | | 1 |
| | 1 |
| | 2 |
| | 2 |
|
| ACE | | 1 |
| | 1 |
| | 1 |
| | 2 |
|
15. Changes in Accumulated Other Comprehensive Income (Exelon)11. Derivative Financial Instruments (All Registrants)
The following tables presentRegistrants 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 Exelon's AOCI, netfair value of tax,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 component: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.
98
|
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2019 | Losses on Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items (a) | | Foreign Currency Items | | AOCI of Investments in Unconsolidated Affiliates (b) | | Total |
| Beginning balance | $ | (2 | ) | | $ | (2,957 | ) | | $ | (29 | ) | | $ | (2 | ) | | $ | (2,990 | ) |
| OCI before reclassifications | — |
| | 6 |
| | (2 | ) | | — |
| | 4 |
|
| Amounts reclassified from AOCI | — |
| | 21 |
| | — |
| | 2 |
| | 23 |
|
| Net current-period OCI | — |
| | 27 |
| | (2 | ) | | 2 |
| | 27 |
|
| Ending balance | $ | (2 | ) | | $ | (2,930 | ) | | $ | (31 | ) | | $ | — |
| | $ | (2,963 | ) |
|
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2018 | Losses on Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items (a) | | Foreign Currency Items | | AOCI of Investments in Unconsolidated Affiliates (b) | | Total |
| Beginning balance | $ | (2 | ) | | $ | (2,890 | ) | | $ | (29 | ) | | $ | — |
| | $ | (2,921 | ) |
| OCI before reclassifications | — |
| | 5 |
| | 2 |
| | — |
| | 7 |
|
| Amounts reclassified from AOCI | — |
| | 45 |
| | — |
| | — |
| | 45 |
|
| Net current-period OCI | — |
| | 50 |
| | 2 |
| | — |
| | 52 |
|
| Ending balance | $ | (2 | ) | | $ | (2,840 | ) | | $ | (27 | ) | | $ | — |
| | $ | (2,869 | ) |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 15 — Changes in Accumulated Other Comprehensive Income
|
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 | Losses on Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items (a) | | Foreign Currency Items | | AOCI of Investments in Unconsolidated Affiliates (b) | | Total |
| Beginning balance | $ | (2 | ) | | $ | (2,960 | ) | | $ | (33 | ) | | $ | — |
| | $ | (2,995 | ) |
| OCI before reclassifications | — |
| | (32 | ) | | 2 |
| | (2 | ) | | (32 | ) |
| Amounts reclassified from AOCI | — |
| | 62 |
| | — |
| | 2 |
| | 64 |
|
| Net current-period OCI | — |
| | 30 |
| | 2 |
| | — |
| | 32 |
|
| Ending balance | $ | (2 | ) | | $ | (2,930 | ) | | $ | (31 | ) | | $ | — |
| | $ | (2,963 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2018 | Gains (Losses) on Cash Flow Hedges | | Unrealized gains (losses) on Marketable Securities | | Pension and Non-Pension Postretirement Benefit Plan Items (a) | | Foreign Currency Items | | AOCI of Investments in Unconsolidated Affiliates (b) | | Total |
| Beginning balance | $ | (14 | ) | | $ | 10 |
| | $ | (2,998 | ) | | $ | (23 | ) | | $ | (1 | ) | | $ | (3,026 | ) |
| OCI before reclassifications | 11 |
| | — |
| | 22 |
| | (4 | ) | | 1 |
| | 30 |
|
| Amounts reclassified from AOCI | 1 |
| | — |
| | 136 |
| | — |
| | — |
| | 137 |
|
| Net current-period OCI | 12 |
| | — |
| | 158 |
| | (4 | ) | | 1 |
| | 167 |
|
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c) | — |
| | (10 | ) | | — |
| | — |
| | — |
| | (10 | ) |
| Ending balance | $ | (2 | ) | | $ | — |
| | $ | (2,840 | ) | | $ | (27 | ) | | $ | — |
| | $ | (2,869 | ) |
_________
| |
(a) | AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 14 — 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 prospectively adopted the new standard Recognition and Measurement of Financial Assets and 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):
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| Pension and non-pension postretirement benefit plans: | | | | | | | |
| Prior service benefit reclassified to periodic benefit cost | $ | 6 |
| | $ | 6 |
| | $ | 18 |
| | $ | 18 |
|
| Actuarial loss reclassified to periodic benefit cost | (13 | ) | | (21 | ) | | (39 | ) | | (65 | ) |
| Pension and non-pension postretirement benefit plans valuation adjustment | — |
| | (2 | ) | | 14 |
| | (8 | ) |
Note 11 — Derivative Financial Instruments 16. CommitmentsAuthoritative guidance about offsetting assets and Contingenciesliabilities 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 referencing 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 that 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)
The following is an update to the current status of commitments and contingencies set forth in Note 22Each 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.
Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon 2018 Form 10-K. See Note 5 — Mergers, Acquisitions and DispositionsGeneration 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 Exelon 2018 Form 10-K for additional information onrespective 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 PHI Merger commitments.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1611 — Derivative Financial Instruments
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 15% 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 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 of the 2019 Form 10-K 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 September 30, 2020 and December 31, 2019 and is not presented in the fair value tables below.
The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of September 30, 2020 and December 31, 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2020 | | Exelon | | Generation | | ComEd | | | | |
| Derivatives | | Total
Derivatives | | Economic
Hedges | | Proprietary
Trading | | Collateral(a)(b) | | Netting(a) | | Subtotal | | Economic
Hedges | | | | | | | | |
Mark-to-market derivative assets
(current assets) | | $ | 471 | | | $ | 2,566 | | | $ | 58 | | | $ | 79 | | | $ | (2,232) | | | $ | 471 | | | $ | 0 | | | | | | | | | |
Mark-to-market derivative assets
(noncurrent assets) | | 383 | | | 1,500 | | | 16 | | | 39 | | | (1,172) | | | 383 | | | 0 | | | | | | | | | |
| Total mark-to-market derivative assets | | 854 | | | 4,066 | | | 74 | | | 118 | | | (3,404) | | | 854 | | | 0 | | | | | | | | | |
Mark-to-market derivative liabilities
(current liabilities) | | (168) | | | (2,414) | | | (40) | | | 84 | | | 2,232 | | | (138) | | | (30) | | | | | | | | | |
Mark-to-market derivative liabilities
(noncurrent liabilities) | | (378) | | | (1,313) | | | (12) | | | 49 | | | 1,172 | | | (104) | | | (274) | | | | | | | | | |
| Total mark-to-market derivative liabilities | | (546) | | | (3,727) | | | (52) | | | 133 | | | 3,404 | | | (242) | | | (304) | | | | | | | | | |
| Total mark-to-market derivative net assets (liabilities) | | $ | 308 | | | $ | 339 | | | $ | 22 | | | $ | 251 | | | $ | 0 | | | $ | 612 | | | $ | (304) | | | | | | | | | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Derivative Financial Instruments
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2019 | | Exelon | | Generation | | ComEd | | | | |
| Description | | Total
Derivatives | | Economic
Hedges | | Proprietary
Trading | | Collateral(a)(b) | | Netting(a) | | Subtotal | | Economic
Hedges | | | | | | | | |
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/(received), $34 million and $511 million represents variation margin on the exchanges at September 30, 2020 and December 31, 2019 respectively.
Economic Hedges (Commodity Price Risk)
Generation. For the three and nine months ended September 30, 2020 and 2019, 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| Income Statement Location | | Gain (Loss) | | Gain (Loss) |
| Operating revenues | | $ | 39 | | | $ | 76 | | | $ | 238 | | | $ | 65 | |
| Purchased power and fuel | | 209 | | | (45) | | | 224 | | | (127) | |
| Total Exelon and Generation | | $ | 248 | | | $ | 31 | | | $ | 462 | | | $ | (62) | |
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 September 30, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 97%-100% and 87%-90% for 2020 and 2021, respectively.
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 three and nine months ended September 30, 2020 and 2019, 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — Derivative Financial Instruments
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 $1,217 million and $1,269 million at September 30, 2020 and December 31, 2019, respectively, for Exelon and $517 million and $569 million at September 30, 2020 and December 31, 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 $171 million and $231 million at September 30, 2020 and December 31, 2019, respectively.
The mark-to-market derivative assets and liabilities as of September 30, 2020 and December 31, 2019 and the mark-to-market gains and losses for the three and nine months ended September 30, 2020 and 2019 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 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — 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 September 30, 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 September 30, 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 | | $ | 638 | | | $ | 27 | | | $ | 611 | | | 0 | | | $ | 0 | |
| Non-investment grade | | 4 | | | 0 | | | 4 | | | | | |
| No external ratings | | | | | | | | | | |
| Internally rated — investment grade | | 168 | | | 1 | | | 167 | | | | | |
| Internally rated — non-investment grade | | 110 | | | 29 | | | 81 | | | | | |
| Total | | $ | 920 | | | $ | 57 | | | $ | 863 | | | 0 | | | $ | 0 | |
| | | | | | | | |
| Net Credit Exposure by Type of Counterparty | | As of September 30, 2020 |
| Financial institutions | | $ | 26 | |
| Investor-owned utilities, marketers, power producers | | 650 | |
| Energy cooperatives and municipalities | | 142 | |
| Other | | 45 | |
| Total | | $ | 863 | |
_________
(a)As of September 30, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $26 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 September 30, 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 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 11 — 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:
| | | | | | | | | | | | | | |
| Credit-Risk Related Contingent Features | | September 30, 2020 | | December 31, 2019 |
Gross fair value of derivative contracts containing this feature(a) | | $ | (750) | | | $ | (956) | |
Offsetting fair value of in-the-money contracts under master netting arrangements(b) | | 535 | | | 649 | |
Net fair value of derivative contracts containing this feature(c) | | $ | (215) | | | $ | (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 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.
As of September 30, 2020 and December 31, 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.
| | | | | | | | | | | | | | |
| | September 30, 2020 | | December 31, 2019 |
| Cash collateral posted | | $ | 288 | | | $ | 982 | |
| Letters of credit posted | | 212 | | | 264 | |
| Cash collateral held | | 68 | | | 103 | |
| Letters of credit held | | 74 | | | 112 | |
| Additional collateral required in the event of a credit downgrade below investment grade | | 1,287 | | | 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, and DPL’s credit rating. As of September 30, 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 ratings as of September 30, 2020, they could have been required to post incremental collateral to its counterparties of $22 million, $31 million and $10 million, respectively.
12. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Debt and Credit Agreements
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 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.
Commercial Paper
The following table reflects the Registrants' commercial paper programs as of September 30, 2020 and December 31, 2019. PECO had no commercial paper borrowings as of both September 30, 2020 and December 31, 2019.
| | | | | | | | | | | | | | | | | | | | | | | |
| Outstanding Commercial
Paper as of | | Average Interest Rate on
Commercial Paper Borrowings as of |
| Commercial Paper Issuer | September 30, 2020 | | December 31, 2019 | | September 30, 2020 | | December 31, 2019 |
Exelon(a) | $ | 141 | | | $ | 870 | | | 0.16 | % | | 2.25 | % |
| Generation | 0 | | | 320 | | | 0 | % | | 1.84 | % |
| ComEd | 141 | | | 130 | | | 0.16 | % | | 2.38 | % |
| | | | | | | |
| BGE | 0 | | | 76 | | | 0 | % | | 2.46 | % |
PHI(b) | 0 | | | 208 | | | 0 | % | | N/A |
| | | | | | | |
| PEPCO | 0 | | | 82 | | | 0 | % | | 2.56 | % |
| DPL | 0 | | | 56 | | | 0 | % | | 2.02 | % |
| ACE | 0 | | | 70 | | | 0 | % | | 2.43 | % |
__________
(a)Includes outstanding commercial paper at Exelon Corporate of $136 million with average interest rates on commercial paper borrowings of 1.92% at December 31, 2019. Exelon Corporate had no outstanding commercial paper borrowings as of September 30, 2020.
(b)Includes the consolidated amounts of Pepco, DPL, and ACE.
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. As of September 30, 2020, the available capacity on Generation’s revolving credit facility was $4.9 billion. See Note 16— Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on the Registrants’ credit facilities.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed on March 19, 2020 and will expire on March 18, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet 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.
Revolving Credit Agreements
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Debt and 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
On May 15, 2020, Generation entered into a credit agreement establishing a $100 million bilateral credit facility. This facility will solely be used by Generation to issue letters of credit, and the maturity date is automatically renewed based on the contingency standards set within the agreement.
During the second and third quarters of 2020, CENG drew on its bilateral credit facility. As of September 30, 2020, there was $40 million outstanding at this facility. The bilateral credit facility with CENG is incorporated within Generation, and supports the issuance of letters of credit and funding for working capital.
Long-Term Debt
Issuance of Long-Term Debt
During the nine months ended September 30, 2020, the following long-term debt was issued:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | |
| Exelon | | Notes | | 4.05 | % | | April 15, 2030 | | $ | 1,250 | | | Repay existing indebtedness and for general corporate purposes. | |
| Exelon | | Notes | | 4.70 | % | | April 15, 2050 | | 750 | | | Repay existing indebtedness and for general corporate purposes. | |
| Generation | | Senior Notes | | 3.25 | % | | June 1, 2025 | | 900 | | | Repay existing indebtedness and for general corporate purposes. | |
| Generation | | Energy Efficiency Project Financing(a) | | 3.95 | % | | December 31, 2020 | | 3 | | | Funding to install energy conservation measures for the Fort Meade project. | |
| Generation | | Energy Efficiency Project Financing(a) | | 2.53 | % | | April 30, 2021 | | 2 | | | Funding to install energy conservation measures for the Fort AP Hill project. | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| 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 129 | | 3.00 | % | | March 1, 2050 | | 650 | | | Repay a portion of outstanding commercial paper obligations and to fund general corporate purposes. | |
| PECO | | First and Refunding Mortgage Bonds | | 2.80 | % | | June 15, 2050 | | 350 | | | Funding 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 | | 2.53 | % | | February 25, 2030 | | 150 | | | Repay existing indebtedness 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 | | 2.53 | % | | June 9, 2030 | | 100 | | | Repay existing indebtedness and for general corporate purposes. | |
DPL(b) | | Tax-Exempt Bonds | | 1.05 | % | | January 1, 2031 | | 78 | | | Refinance existing indebtedness. | |
| ACE | | Tax-Exempt First Mortgage Bonds | | 2.25 | % | | June 1, 2029 | | 23 | | | Refinance existing indebtedness. | |
| ACE | | First Mortgage Bonds | | 3.24 | % | | June 9, 2050 | | 100 | | | Repay existing indebtedness and for general corporate purposes. | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 12 — Debt and Credit Agreements
__________
(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)The bonds have a 1.05% interest rate through July 2025.
Debt Covenants
As of September 30, 2020, the Registrants are in compliance with debt covenants.
Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing. 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.
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. As of September 30, 2020, approximately $470 million was outstanding. In addition, Generation has issued letters of credit to support its equity investment in the project. As of September 30, 2020, Generation had $37 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.
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 September 30, 2020.
See Note 8 — Asset Impairments for additional information.
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 loan is scheduled to mature on November 28, 2024. As of September 30, 2020, approximately $710 million was outstanding.
See Note 16— Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on nonrecourse debt.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — Fair Value of Financial Assets and Liabilities
13. 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.
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 September 30, 2020 and December 31, 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 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 | | $ | 37,589 | | | $ | 40,816 | | | $ | 3,237 | | | $ | 44,053 | | | $ | 36,039 | | | $ | 37,453 | | | $ | 2,580 | | | $ | 40,033 | |
| Generation | | 6,756 | | | 6,250 | | | 1,401 | | | 7,651 | | | 7,974 | | | 7,304 | | | 1,366 | | | 8,670 | |
| ComEd | | 8,981 | | | 10,970 | | | 0 | | | 10,970 | | | 8,491 | | | 9,848 | | | 0 | | | 9,848 | |
| PECO | | 3,753 | | | 4,498 | | | 50 | | | 4,548 | | | 3,405 | | | 3,868 | | | 50 | | | 3,918 | |
| BGE | | 3,664 | | | 4,263 | | | 0 | | | 4,263 | | | 3,270 | | | 3,649 | | | 0 | | | 3,649 | |
| PHI | | 7,020 | | | 6,082 | | | 1,786 | | | 7,868 | | | 6,563 | | | 5,902 | | | 1,164 | | | 7,066 | |
| Pepco | | 3,164 | | | 3,343 | | | 739 | | | 4,082 | | | 2,864 | | | 3,198 | | | 388 | | | 3,586 | |
| DPL | | 1,676 | | | 1,463 | | | 449 | | | 1,912 | | | 1,567 | | | 1,408 | | | 311 | | | 1,719 | |
| ACE | | 1,417 | | | 1,017 | | | 598 | | | 1,615 | | | 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 | | $ | 1,207 | | | $ | 1,042 | | | $ | 0 | | | $ | 1,042 | | | $ | 1,199 | | | $ | 1,055 | | | $ | 0 | | | $ | 1,055 | |
| Generation | | 1,207 | | | 1,042 | | | 0 | | | 1,042 | | | 1,199 | | | 1,055 | | | 0 | | | 1,055 | |
__________
(a)Includes unamortized debt issuance costs which are not fair valued.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — Fair Value of Financial Assets and Liabilities
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 as of September 30, 2020 and December 31, 2019:
Exelon and Generation
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation |
| As of September 30, 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) | $ | 1,687 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 1,687 | | | $ | 270 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 270 | |
| NDT fund investments | | | | | | | | | | | | | | | | | | | |
Cash equivalents(b) | 313 | | | 91 | | | 0 | | | 0 | | | 404 | | | 313 | | | 91 | | | 0 | | | 0 | | | 404 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Equities | 3,345 | | | 1,794 | | | 0 | | | 1,370 | | | 6,509 | | | 3,345 | | | 1,794 | | | 0 | | | 1,370 | | | 6,509 | |
| Fixed income | | | | | | | | | | | | | | | | | | | |
| Corporate debt | 0 | | | 1,516 | | | 280 | | | 0 | | | 1,796 | | | 0 | | | 1,516 | | | 280 | | | 0 | | | 1,796 | |
| U.S. Treasury and agencies | 1,843 | | | 137 | | | 0 | | | 0 | | | 1,980 | | | 1,843 | | | 137 | | | 0 | | | 0 | | | 1,980 | |
| Foreign governments | 0 | | | 52 | | | 0 | | | 0 | | | 52 | | | 0 | | | 52 | | | 0 | | | 0 | | | 52 | |
| State and municipal debt | 0 | | | 104 | | | 0 | | | 0 | | | 104 | | | 0 | | | 104 | | | 0 | | | 0 | | | 104 | |
| Other | 0 | | | 40 | | | 0 | | | 1,010 | | | 1,050 | | | 0 | | | 40 | | | 0 | | | 1,010 | | | 1,050 | |
| Fixed income subtotal | 1,843 | | | 1,849 | | | 280 | | | 1,010 | | | 4,982 | | | 1,843 | | | 1,849 | | | 280 | | | 1,010 | | | 4,982 | |
| Private credit | 0 | | | 0 | | | 238 | | | 533 | | | 771 | | | 0 | | | 0 | | | 238 | | | 533 | | | 771 | |
| Private equity | 0 | | | 0 | | | 0 | | | 439 | | | 439 | | | 0 | | | 0 | | | 0 | | | 439 | | | 439 | |
| Real estate | 0 | | | 0 | | | 0 | | | 650 | | | 650 | | | 0 | | | 0 | | | 0 | | | 650 | | | 650 | |
| | | | | | | | | | | | | | | | | | | |
NDT fund investments subtotal(c)(d) | 5,501 | | | 3,734 | | | 518 | | | 4,002 | | | 13,755 | | | 5,501 | | | 3,734 | | | 518 | | | 4,002 | | | 13,755 | |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 58 | | | 0 | | | 0 | | | 0 | | | 58 | | | 4 | | | 0 | | | 0 | | | 0 | | | 4 | |
| Mutual funds | 88 | | | 0 | | | 0 | | | 0 | | | 88 | | | 28 | | | 0 | | | 0 | | | 0 | | | 28 | |
| Fixed income | 0 | | | 11 | | | 0 | | | 0 | | | 11 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Life insurance contracts | 0 | | | 84 | | | 34 | | | 0 | | | 118 | | | 0 | | | 27 | | | 0 | | | 0 | | | 27 | |
| Rabbi trust investments subtotal | 146 | | | 95 | | | 34 | | | 0 | | | 275 | | | 32 | | | 27 | | | 0 | | | 0 | | | 59 | |
| Commodity derivative assets | | | | | | | | | | | | | | | | | | | |
| Economic hedges | 776 | | | 1,737 | | | 1,553 | | | 0 | | | 4,066 | | | 776 | | | 1,737 | | | 1,553 | | | 0 | | | 4,066 | |
| Proprietary trading | 0 | | | 37 | | | 37 | | | 0 | | | 74 | | | 0 | | | 37 | | | 37 | | | 0 | | | 74 | |
Effect of netting and allocation of collateral(e)(f) | (656) | | | (1,594) | | | (1,036) | | | 0 | | | (3,286) | | | (656) | | | (1,594) | | | (1,036) | | | 0 | | | (3,286) | |
| Commodity derivative assets subtotal | 120 | | | 180 | | | 554 | | | 0 | | | 854 | | | 120 | | | 180 | | | 554 | | | 0 | | | 854 | |
| DPP consideration | 0 | | | 732 | | | 0 | | | 0 | | | 732 | | | 0 | | | 732 | | | 0 | | | 0 | | | 732 | |
| Total assets | 7,454 | | | 4,741 | | | 1,106 | | | 4,002 | | | 17,303 | | | 5,923 | | | 4,673 | | | 1,072 | | | 4,002 | | | 15,670 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation |
| As of September 30, 2020 | 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 | (700) | | | (1,692) | | | (1,639) | | | 0 | | | (4,031) | | | (700) | | | (1,692) | | | (1,335) | | | 0 | | | (3,727) | |
| Proprietary trading | 0 | | | (36) | | | (16) | | | 0 | | | (52) | | | 0 | | | (36) | | | (16) | | | 0 | | | (52) | |
Effect of netting and allocation of collateral(e)(f) | 699 | | | 1,708 | | | 1,130 | | | 0 | | | 3,537 | | | 699 | | | 1,708 | | | 1,130 | | | 0 | | | 3,537 | |
| Commodity derivative liabilities subtotal | (1) | | | (20) | | | (525) | | | 0 | | | (546) | | | (1) | | | (20) | | | (221) | | | 0 | | | (242) | |
| Deferred compensation obligation | 0 | | | (135) | | | 0 | | | 0 | | | (135) | | | 0 | | | (37) | | | 0 | | | 0 | | | (37) | |
| Total liabilities | (1) | | | (155) | | | (525) | | | 0 | | | (681) | | | (1) | | | (57) | | | (221) | | | 0 | | | (279) | |
| Total net assets | $ | 7,453 | | | $ | 4,586 | | | $ | 581 | | | $ | 4,002 | | | $ | 16,622 | | | $ | 5,922 | | | $ | 4,616 | | | $ | 851 | | | $ | 4,002 | | | $ | 15,391 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — 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 | | | 1,753 | | | 0 | | | 1,388 | | | 6,494 | | | 3,353 | | | 1,753 | | | 0 | | | 1,388 | | | 6,494 | |
| Fixed income | | | | | | | | | | | | | | | | | | | |
| Corporate debt | 0 | | | 1,469 | | | 257 | | | 0 | | | 1,726 | | | 0 | | | 1,469 | | | 257 | | | 0 | | | 1,726 | |
| 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 | | | 1,765 | | | 257 | | | 953 | | | 4,783 | | | 1,808 | | | 1,765 | | | 257 | | | 953 | | | 4,783 | |
| 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(c)(d) | 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(e)(f) | (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 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — 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 |
| 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(e)(f) | 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 $677 million and $373 million at September 30, 2020 and December 31, 2019, respectively, and restricted cash of $116 million and $110 million at September 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $137 million and $177 million at September 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $408 million and $177 million at September 30, 2020 and December 31, 2019, respectively, and restricted cash of $45 million and $58 million at September 30, 2020 and December 31, 2019, respectively.
(b)Includes $121 million and $90 million of cash received from outstanding repurchase agreements at September 30, 2020 and December 31, 2019, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.
(c)Includes derivative assets of less than $1 million and $2 million, which have total notional amounts of $658 million and $724 million at September 30, 2020 and December 31, 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.
(d)Excludes net liabilities of $208 million and $147 million at September 30, 2020 and December 31, 2019, respectively, which include certain derivative assets that have notional amounts of $153 million and $99 million at September 30, 2020 and December 31, 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.
(e)Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $43 million, $114 million, and $94 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of September 30, 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.
(f)Of the collateral posted/(received), $34 million and $511 million represents variation margin on the exchanges as of September 30, 2020 and December 31, 2019, respectively.
As of September 30, 2020, Exelon and Generation have outstanding commitments to invest in fixed income, private credit, private equity and real estate investments of approximately $52 million, $119 million, $299 million, and $395 million, respectively. These commitments will be funded by Generation’s existing NDT funds.
Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $76 million and $66 million as of September 30, 2020, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three and nine months ended September 30, 2020.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — Fair Value of Financial Assets and Liabilities
ComEd, PECO and BGE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ComEd | | PECO | | BGE |
| As of September 30, 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) | $ | 396 | | | $ | 0 | | | $ | 0 | | | $ | 396 | | | $ | 184 | | | $ | 0 | | | $ | 0 | | | $ | 184 | | | $ | 298 | | | $ | 0 | | | $ | 0 | | | $ | 298 | |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Mutual funds | 0 | | | 0 | | | 0 | | | 0 | | | 9 | | | 0 | | | 0 | | | 9 | | | 9 | | | 0 | | | 0 | | | 9 | |
| 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 | | | 9 | | | 0 | | | 0 | | | 9 | |
| Total assets | 396 | | | 0 | | | 0 | | | 396 | | | 193 | | | 13 | | | 0 | | | 206 | | | 307 | | | 0 | | | 0 | | | 307 | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred compensation obligation | 0 | | | (7) | | | 0 | | | (7) | | | 0 | | | (8) | | | 0 | | | (8) | | | 0 | | | (5) | | | 0 | | | (5) | |
Mark-to-market derivative liabilities(b) | 0 | | | 0 | | | (304) | | | (304) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total liabilities | 0 | | | (7) | | | (304) | | | (311) | | | 0 | | | (8) | | | 0 | | | (8) | | | 0 | | | (5) | | | 0 | | | (5) | |
| Total net assets (liabilities) | $ | 396 | | | $ | (7) | | | $ | (304) | | | $ | 85 | | | $ | 193 | | | $ | 5 | | | $ | 0 | | | $ | 198 | | | $ | 307 | | | $ | (5) | | | $ | 0 | | | $ | 302 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred compensation obligation | 0 | | | (8) | | | 0 | | | (8) | | | 0 | | | (9) | | | 0 | | | (9) | | | 0 | | | (5) | | | 0 | | | (5) | |
Mark-to-market derivative liabilities(b) | 0 | | | 0 | | | (301) | | | (301) | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| 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 $76 million and $90 million at September 30, 2020 and December 31, 2019, respectively, and restricted cash of $36 million and $33 million at September 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $127 million and $163 million at September 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $65 million and $12 million at September 30, 2020 and December 31, 2019, respectively. BGE excludes cash of $28 million and $24 million at September 30, 2020 and December 31, 2019, respectively, and restricted cash of $1 million at both September 30, 2020 and December 31, 2019.
(b)The Level 3 balance consists of the current and noncurrent liability of $30 million and $274 million, respectively, at September 30, 2020 and $32 million and $269 million, respectively, at December 31, 2019 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 13 — Fair Value of Financial Assets and Liabilities
PHI, Pepco, DPL and ACE
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| As of September 30, 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) | $ | 166 | | | $ | 0 | | | $ | 0 | | | $ | 166 | | | $ | 124 | | | $ | 0 | | | $ | 0 | | | $ | 124 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Rabbi trust investments | | | | | | | | | | | | | | | |
| Cash equivalents | 52 | | | 0 | | | 0 | | | 52 | | | 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 | 66 | | | 37 | | | 34 | | | 137 | | | 58 | | | 36 | | | 41 | | | 135 | |
| Total assets | 232 | | | 37 | | | 34 | | | 303 | | | 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 | $ | 232 | | | $ | 20 | | | $ | 34 | | | $ | 286 | | | $ | 182 | | | $ | 17 | | | $ | 41 | | | $ | 240 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pepco | | DPL | | ACE |
| As of September 30, 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) | $ | 112 | | | $ | 0 | | | $ | 0 | | | $ | 112 | | | $ | 17 | | | $ | 0 | | | $ | 0 | | | $ | 17 | | | $ | 14 | | | $ | 0 | | | $ | 0 | | | $ | 14 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | |
| Cash equivalents | 51 | | | 0 | | | 0 | | | 51 | | | 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 | 51 | | | 28 | | | 34 | | | 113 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total assets | 163 | | | 28 | | | 34 | | | 225 | | | 17 | | | 0 | | | 0 | | | 17 | | | 14 | | | 0 | | | 0 | | | 14 | |
| 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 | $ | 163 | | | $ | 26 | | | $ | 34 | | | $ | 223 | | | $ | 17 | | | $ | 0 | | | $ | 0 | | | $ | 17 | | | $ | 14 | | | $ | 0 | | | $ | 0 | | | $ | 14 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 (liabilities) | $ | 77 | | | $ | 24 | | | $ | 41 | | | $ | 142 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 16 | | | $ | 0 | | | $ | 0 | | | $ | 16 | |
__________
(a)PHI excludes cash of $78 million and $57 million at September 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $10 million and $14 million at September 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $46 million and $29 million at September 30, 2020 and December 31, 2019, respectively. DPL excludes cash of $9 million and $13 million at September 30, 2020 and December 31, 2019, respectively. ACE excludes cash of $13 million and $12 million at September 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $10 million and $14 million at September 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.
Reconciliation of Level 3 Assets and Liabilities
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PHI and Pepco | | | | |
| Three Months Ended September 30, 2020 | Total | | NDT Fund
Investments | | Mark-to-Market
Derivatives | | | | Total Generation | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | | | Eliminated in Consolidation |
| Balance as of June 30, 2020 | $ | 883 | | | $ | 499 | | | $ | 659 | | | | | $ | 1,158 | | | $ | (318) | | | $ | 43 | | | | | $ | 0 | |
| Total realized / unrealized gains (losses) | | | | | | | | | | | | | | | | | |
| Included in net income | (327) | | | 3 | | | (318) | | (a) | | | (315) | | | 0 | | | (12) | | | | | 0 | |
| Included in noncurrent payables to affiliates | 0 | | | 18 | | | 0 | | | | | 18 | | | 0 | | | 0 | | | | | (18) | |
| | | | | | | | | | | | | | | | | |
| Included in regulatory assets/liabilities | 32 | | | 0 | | | 0 | | | | | 0 | | | 14 | | (b) | 0 | | | | | 18 | |
| Change in collateral | (79) | | | 0 | | | (79) | | | | | (79) | | | 0 | | | 0 | | | | | 0 | |
| Purchases, sales, issuances and settlements | | | | | | | | | | | | | | | | | |
| Purchases | 66 | | | 1 | | | 65 | | | | | 66 | | | 0 | | | 0 | | | | | 0 | |
| Sales | (3) | | | 0 | | | (3) | | | | | (3) | | | 0 | | | 0 | | | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Settlements | 0 | | | (3) | | | 0 | | | | | (3) | | | 0 | | | 3 | | | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Transfers out of Level 3 | 9 | | | 0 | | | 9 | | (c) | | | 9 | | | 0 | | | 0 | | | | | 0 | |
| Balance at September 30, 2020 | $ | 581 | | | $ | 518 | | | $ | 333 | | | | | $ | 851 | | | $ | (304) | | | $ | 34 | | | | | $ | 0 | |
| The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2020 | $ | (222) | | | $ | 3 | | | $ | (213) | | | | | $ | (210) | | | $ | 0 | | | $ | (12) | | | | | $ | 0 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PHI and Pepco | | | | |
| Nine months ended September 30, 2020 | Total | | NDT Fund
Investments | | Mark-to-Market
Derivatives | | | | Total Generation | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | | | Eliminated in Consolidation |
| Balance as of December 31, 2019 | $ | 1,068 | | | $ | 511 | | | $ | 817 | | | | | $ | 1,328 | | | $ | (301) | | | $ | 41 | | | | | $ | 0 | |
| Total realized / unrealized gains (losses) | | | | | | | | | | | | | | | | | |
| Included in net income | (483) | | | 1 | | | (474) | | (a) | | | (473) | | | 0 | | | (10) | | | | | 0 | |
| Included in noncurrent payables to affiliates | 0 | | | 17 | | | 0 | | | | | 17 | | | 0 | | | 0 | | | | | (17) | |
| | | | | | | | | | | | | | | | | |
| Included in regulatory assets | 14 | | | 0 | | | 0 | | | | | 0 | | | (3) | | (b) | 0 | | | | | 17 | |
| Change in collateral | (120) | | | 0 | | | (120) | | | | | (120) | | | 0 | | | 0 | | | | | 0 | |
| Purchases, sales, issuances and settlements | | | | | | | | | | | | | | | | | |
| Purchases | 136 | | | 6 | | | 130 | | | | | 136 | | | 0 | | | 0 | | | | | 0 | |
| Sales | (27) | | | 0 | | | (27) | | | | | (27) | | | 0 | | | 0 | | | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Settlements | (15) | | | (18) | | | 0 | | | | | (18) | | | 0 | | | 3 | | | | | 0 | |
| Transfers into Level 3 | (5) | | | 1 | | | (6) | | (c) | | | (5) | | | 0 | | | 0 | | | | | 0 | |
| Transfers out of Level 3 | 13 | | | 0 | | | 13 | | (c) | | | 13 | | | 0 | | | 0 | | | | | 0 | |
| Balance as of September 30, 2020 | $ | 581 | | | $ | 518 | | | $ | 333 | | | | | $ | 851 | | | $ | (304) | | | $ | 34 | | | | | $ | 0 | |
| The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2020 | $ | (107) | | | $ | 1 | | | $ | (98) | | | | | $ | (97) | | | $ | 0 | | | $ | (10) | | | | | $ | 0 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PHI and Pepco | | | | |
| Three Months Ended September 30, 2019 | Total | | NDT Fund
Investments | | Mark-to-Market
Derivatives | | | | Total Generation | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | | | Eliminated in Consolidation |
| Balance as of June 30, 2019 | $ | 1,179 | | | $ | 539 | | | $ | 873 | | | | | $ | 1,412 | | | $ | (273) | | | $ | 40 | | | | | $ | 0 | |
| Total realized / unrealized gains (losses) | | | | | | | | | | | | | | | | | |
| Included in net income | (171) | | | 2 | | | (173) | | (a) | | | (171) | | | 0 | | | 0 | | | | | 0 | |
| Included in noncurrent payables to affiliates | 0 | | | 11 | | | 0 | | | | | 11 | | | 0 | | | 0 | | | | | (11) | |
| Included in regulatory assets | 4 | | | 0 | | | 0 | | | | | 0 | | | (7) | | (b) | 0 | | | | | 11 | |
| Change in collateral | 41 | | | 0 | | | 41 | | | | | 41 | | | 0 | | | 0 | | | | | 0 | |
| Purchases, sales, issuances and settlements | | | | | | | | | | | | | | | | | |
| Purchases | 53 | | | 1 | | | 52 | | | | | 53 | | | 0 | | | 0 | | | | | 0 | |
| Sales | (22) | | | (21) | | | (1) | | | | | (22) | | | 0 | | | 0 | | | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Settlements | (18) | | | (18) | | | 0 | | | | | (18) | | | 0 | | | 0 | | | | | 0 | |
| Transfers into Level 3 | 1 | | | 0 | | | 1 | | (c) | | | 1 | | | 0 | | | 0 | | | | | 0 | |
| Transfers out of Level 3 | (11) | | | 0 | | | (11) | | (c) | | | (11) | | | 0 | | | 0 | | | | | 0 | |
| Balance as of September 30, 2019 | $ | 1,056 | | | $ | 514 | | | $ | 782 | | | | | $ | 1,296 | | | $ | (280) | | | $ | 40 | | | | | $ | 0 | |
| The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2019 | $ | (18) | | | $ | 2 | | | $ | (20) | | | | | $ | (18) | | | $ | 0 | | | $ | 0 | | | | | $ | 0 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — Fair Value of Financial Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PHI and Pepco | | | | |
| Nine Months Ended September 30, 2019 | Total | | NDT Fund
Investments | | Mark-to-Market
Derivatives | | | | Total Generation | | Mark-to-Market
Derivatives | | Life Insurance Contracts | | | | Eliminated in Consolidation |
| Balance as of December 31, 2018 | $ | 907 | | | $ | 543 | | | $ | 575 | | | | | $ | 1,118 | | | $ | (249) | | | $ | 38 | | | | | $ | 0 | |
| Total realized / unrealized gains (losses) | | | | | | | | | | | | | | | | | |
| Included in net income | (125) | | | 5 | | | (132) | | (a) | | | (127) | | | 0 | | | 2 | | | | | 0 | |
| Included in noncurrent payables to affiliates | 0 | | | 32 | | | 0 | | | | | 32 | | | 0 | | | 0 | | | | | (32) | |
| | | | | | | | | | | | | | | | | |
| Included in regulatory assets | 1 | | | 0 | | | 0 | | | | | 0 | | | (31) | | (b) | 0 | | | | | 32 | |
| Change in collateral | 227 | | | 0 | | | 227 | | | | | 227 | | | 0 | | | 0 | | | | | 0 | |
| Purchases, sales, issuances and settlements | | | | | | | | | | | | | | | | | |
| Purchases | 163 | | | 43 | | | 120 | | | | | 163 | | | 0 | | | 0 | | | | | 0 | |
| Sales | (23) | | | (21) | | | (2) | | | | | (23) | | | 0 | | | 0 | | | | | 0 | |
| | | | | | | | | | | | | | | | | |
| Settlements | (88) | | | (88) | | | 0 | | | | | (88) | | | 0 | | | 0 | | | | | 0 | |
| Transfers into Level 3 | 5 | | | 0 | | | 5 | | (c) | | | 5 | | | 0 | | | 0 | | | | | 0 | |
| Transfers out of Level 3 | (11) | | | 0 | | | (11) | | (c) | | | (11) | | | 0 | | | 0 | | | | | 0 | |
| Balance as of September 30, 2019 | $ | 1,056 | | | $ | 514 | | | $ | 782 | | | | | $ | 1,296 | | | $ | (280) | | | $ | 40 | | | | | $ | 0 | |
| The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2019 | $ | 173 | | | $ | 5 | | | $ | 166 | | | | | $ | 171 | | | $ | 0 | | | $ | 2 | | | | | $ | 0 | |
__________
(a)Includes a reduction for the reclassification of $105 million and $376 million of realized losses due to the settlement of derivative contracts for the three and nine months ended September 30, 2020. Includes a reduction for the reclassification of $153 million and $298 million of realized losses due to the settlement of derivative contracts for the three and nine months ended September 30, 2019.
(b)Includes 1) an increase in fair value of $9 million for the three months ended September 30, 2020 and a decrease in fair value of $7 million, $26 million, and $31 million for the three months ended September 30, 2019, nine months ended September 30, 2020, and nine months ended September 30, 2019, respectively, and 2) an increase in realized losses recorded in purchased power expense due to settlements associated with floating-to-fixed energy swap contracts with unaffiliated suppliers of $5 million, $4 million, $23 million, and $17 million for the three months ended September 30, 2020, three months ended September 30, 2019, nine months ended September 30, 2020, and nine months ended September 30, 2019, respectively.
(c)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.
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 three and nine months ended September 30, 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 realized losses for the three months ended September 30, 2020 | $ | (305) | | | $ | (13) | | | $ | (12) | | | $ | 0 | | | $ | (305) | | | $ | (13) | | | $ | 0 | | | | | | | | | $ | (12) | |
| Total realized losses for the nine months ended September 30, 2020 | (370) | | | (104) | | | (10) | | | 0 | | | (370) | | | (104) | | | 0 | | | | | | | | | (10) | |
| Total unrealized (losses) gains for the three months ended September 30, 2020 | (216) | | | 3 | | | (12) | | | 3 | | | (216) | | | 3 | | | 3 | | | | | | | | | (12) | |
| Total unrealized (losses) gains for the nine months ended September 30, 2020 | (50) | | | (48) | | | (10) | | | 1 | | | (50) | | | (48) | | | 1 | | | | | | | | | (10) | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — 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 realized (losses) gains for the three months ended September 30, 2019 | $ | (25) | | | $ | (148) | | | $ | 0 | | | $ | 2 | | | $ | (25) | | | $ | (148) | | | $ | 2 | | | $ | 0 | |
| Total realized gains (losses) for the nine months ended September 30, 2019 | 122 | | | (254) | | | 0 | | | 5 | | | 122 | | | (254) | | | 5 | | | 0 | |
| Total unrealized gains (losses) for the three months ended September 30, 2019 | 99 | | | (119) | | | 0 | | | 2 | | | 99 | | | (119) | | | 2 | | | 0 | |
| Total unrealized gains (losses) gains for the nine months ended September 30, 2019 | 368 | | | (202) | | | 2 | | | 5 | | | 368 | | | (202) | | | 5 | | | 2 | |
Valuation Techniques Used to Determine Fair Value
Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 17 — Fair Value of Financial Assets and Liabilities of the Exelon 2019 Form 10-K.
Valuation Techniques Used to Determine Net asset Value (Exelon and Generation)
Certain NDT Fund Investments are not classified within the fair value hierarchy and are included under the heading “Not subject to leveling” in the table above. These investments are measured at fair value using NAV per share as a practical expedient and include commingled funds, mutual funds which are not publicly quoted, managed private credit funds, private equity and real estate funds.
For commingled funds and mutual funds, which are not publicly quoted, the fair value is primarily derived from the quoted prices in active markets on the underlying securities and can typically be redeemed monthly with 30 or less days of notice and without further restrictions. 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. 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. 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.
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 5 - Accounts Receivable for additional information on the sale of certain receivables.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 13 — Fair Value of Financial Assets and Liabilities
Mark-to-Market Derivatives (Exelon, Generation and ComEd)
The table below discloses the significant inputs to the forward curve used to value mark-to-market derivatives.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Type of trade | | Fair Value at September 30, 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) | | $ | 218 | | | $ | 558 | | | Discounted
Cash Flow | | Forward power
price | | $9 | - | $113 | $29 | | $9 | - | $180 | $29 |
| | | | | | | | Forward gas
price | | $1.84 | - | $4.69 | $2.77 | | $0.83 | - | $10.72 | $2.55 |
| | | | | | Option
Model | | Volatility
percentage | | 10% | - | 160% | 57% | | 8% | - | 236% | 70% |
| | | | | | | | | | | | | | | | | | |
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b) | | $ | 21 | | | $ | 45 | | | Discounted
Cash Flow | | Forward power
price | | $9 | - | $115 | $31 | | $25 | - | $180 | $33 |
| | | | | | | | | | | | | | | | | | |
| Mark-to-market derivatives (Exelon and ComEd) | | $ | (304) | | | $ | (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 arithmetic 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 $94 million and $214 million as of September 30, 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.
14. 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 September 30, 2019:2020:
|
| | | | | | | | | | | | | | | | | | | |
| Description | Exelon | | PHI | | Pepco | | DPL | | ACE |
| Total commitments | $ | 513 |
| | $ | 320 |
| | $ | 120 |
| | $ | 89 |
| | $ | 111 |
|
Remaining commitments(a) | 112 |
| | 82 |
| | 67 |
| | 9 |
| | 6 |
|
119
_________
| |
(a) | Remaining commitments extend through 2026 and include rate credits, energy efficiency programs. and delivery system modernization. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Commitments and Contingencies
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Description | Exelon | | PHI | | Pepco | | DPL | | ACE |
| Total commitments | $ | 513 | | | $ | 320 | | | $ | 120 | | | $ | 89 | | | $ | 111 | |
Remaining commitments(a) | 87 | | | 69 | | | 57 | | | 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 $127$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 September 30, 2019,2020, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $107 million.$118 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 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 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1614 — Commitments and Contingencies
Commercial Commitments (All Registrants). The Registrants’ commercial commitments as of September 30, 2019,2020, representing commitments potentially triggered by future events were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expiration within |
| Total | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 and beyond |
| Exelon | | | | | | | | | | | | | |
| Letters of credit | $ | 1,462 | | | $ | 224 | | | $ | 1,238 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Surety bonds(a) | 1,056 | | | 388 | | | 641 | | | 27 | | | 0 | | | 0 | | | 0 | |
| Financing trust guarantees | 378 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 378 | |
Guaranteed lease residual values(b) | 28 | | | 0 | | | 2 | | | 3 | | | 3 | | | 6 | | | 14 | |
| Total commercial commitments | $ | 2,924 | | | $ | 612 | | | $ | 1,881 | | | $ | 30 | | | $ | 3 | | | $ | 6 | | | $ | 392 | |
| | | | | | | | | | | | | |
| Generation | | | | | | | | | | | | | |
| Letters of credit | $ | 1,447 | | | $ | 220 | | | $ | 1,227 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Surety bonds(a) | 912 | | | 374 | | | 511 | | | 27 | | | 0 | | | 0 | | | 0 | |
| Total commercial commitments | $ | 2,359 | | | $ | 594 | | | $ | 1,738 | | | $ | 27 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | | | | |
| ComEd | | | | | | | | | | | | | |
| Letters of credit | $ | 7 | | | $ | 0 | | | $ | 7 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Surety bonds(a) | 16 | | | 5 | | | 11 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Financing trust guarantees | 200 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 200 | |
| Total commercial commitments | $ | 223 | | | $ | 5 | | | $ | 18 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 200 | |
| | | | | | | | | | | | | |
| PECO | | | | | | | | | | | | | |
Surety bonds(a) | $ | 2 | | | $ | 0 | | | $ | 2 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Financing trust guarantees | 178 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 178 | |
| Total commercial commitments | $ | 180 | | | $ | 0 | | | $ | 2 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 178 | |
| | | | | | | | | | | | | |
| BGE | | | | | | | | | | | | | |
| Letters of credit | $ | 2 | | | $ | 2 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Surety bonds(a) | 3 | | | 1 | | | 2 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total commercial commitments | $ | 5 | | | $ | 3 | | | $ | 2 | | | $ | 0 | | | $ | 0 | | | $ | — | | | $ | 0 | |
| | | | | | | | | | | | | |
| PHI | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Surety bonds(a) | $ | 21 | | | $ | 3 | | | $ | 18 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Guaranteed lease residual values(b) | 28 | | | 0 | | | 2 | | | 3 | | | 3 | | | 6 | | | 14 | |
| Total commercial commitments | $ | 49 | | | $ | 3 | | | $ | 20 | | | $ | 3 | | | $ | 3 | | | $ | 6 | | | $ | 14 | |
| | | | | | | | | | | | | |
| Pepco | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Surety bonds(a) | $ | 14 | | | $ | 0 | | | $ | 14 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Guaranteed lease residual values(b) | 9 | | | 0 | | | 0 | | | 1 | | | 1 | | | 2 | | | 5 | |
| Total commercial commitments | $ | 23 | | | $ | 0 | | | $ | 14 | | | $ | 1 | | | $ | 1 | | | $ | 2 | | | $ | 5 | |
| | | | | | | | | | | | | |
| DPL | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Surety bonds(a) | $ | 4 | | | $ | 2 | | | $ | 2 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Guaranteed lease residual values(b) | 12 | | | 0 | | | 1 | | | 1 | | | 1 | | | 3 | | | 6 | |
| Total commercial commitments | $ | 16 | | | $ | 2 | | | $ | 3 | | | $ | 1 | | | $ | 1 | | | $ | 3 | | | $ | 6 | |
| | | | | | | | | | | | | |
| ACE | | | | | | | | | | | | | |
Surety bonds(a) | $ | 3 | | | $ | 1 | | | $ | 2 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Guaranteed lease residual values(b) | 7 | | | 0 | | | 1 | | | 1 | | | 1 | | | 1 | | | 3 | |
| Total commercial commitments | $ | 10 | | | $ | 1 | | | $ | 3 | | | $ | 1 | | | $ | 1 | | | $ | 1 | | | $ | 3 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Expiration within |
| | Total | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
| Exelon | | | | | | | | | | | | | |
| Letters of credit | $ | 1,718 |
| | $ | 1,192 |
| | $ | 515 |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | 991 |
| | 315 |
| | 638 |
| | 38 |
| | — |
| | — |
| | — |
|
| Financing trust guarantees | 378 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 378 |
|
Guaranteed lease residual values(b) | 26 |
| | — |
| | 2 |
| | 3 |
| | 4 |
| | 3 |
| | 15 |
|
| Total commercial commitments | $ | 3,113 |
| | $ | 1,507 |
| | $ | 1,155 |
| | $ | 52 |
| | $ | 4 |
|
| $ | 3 |
| | $ | 393 |
|
| | | | | | | | | | | | | | |
| Generation | | | | | | | | | | | | | |
| Letters of credit | $ | 1,686 |
| | $ | 1,179 |
| | $ | 496 |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | 790 |
| | 298 |
| | 492 |
| | — |
| | — |
| | — |
| | — |
|
| Total commercial commitments | $ | 2,476 |
| | $ | 1,477 |
| | $ | 988 |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | |
| ComEd | | | | | | | | | | | | | |
| Letters of credit | $ | 7 |
| | $ | 4 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | 50 |
| | 5 |
| | 43 |
| | 2 |
| | — |
| | — |
| | — |
|
| Financing trust guarantees | 200 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 200 |
|
| Total commercial commitments | $ | 257 |
| | $ | 9 |
| | $ | 46 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 200 |
|
| | | | | | | | | | | | | | |
| PECO | | | | | | | | | | | | | |
Surety bonds(a) | $ | 9 |
| | $ | 1 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Financing trust guarantees | 178 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 178 |
|
| Total commercial commitments | $ | 187 |
| | $ | 1 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 178 |
|
| | | | | | | | | | | | | | |
| BGE | | | | | | | | | | | | | |
| Letters of credit | $ | 8 |
| | $ | 2 |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | 17 |
| | 2 |
| | 15 |
| | — |
| | — |
| | — |
| | — |
|
| Total commercial commitments | $ | 25 |
| | $ | 4 |
| | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | |
| PHI | | | | | | | | | | | | | |
| Letters of credit | $ | 11 |
| | $ | 1 |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | 24 |
| | 5 |
| | 19 |
| | — |
| | — |
| | — |
| | — |
|
Guaranteed lease residual values(b) | 26 |
| | — |
| | 2 |
| | 3 |
| | 4 |
| | 3 |
| | 15 |
|
| Total commercial commitments | $ | 61 |
| | $ | 6 |
| | $ | 31 |
| | $ | 3 |
| | $ | 4 |
| | $ | 3 |
| | $ | 15 |
|
| | | | | | | | | | | | | | |
| Pepco | | | | | | | | | | | | | |
| Letters of credit | $ | 10 |
| | $ | — |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | 17 |
| | 2 |
| | 15 |
| | — |
| | — |
| | — |
| | — |
|
Guaranteed lease residual values(b) | 9 |
| | — |
| | — |
| | 1 |
| | 1 |
| | 1 |
| | 6 |
|
| Total commercial commitments | $ | 36 |
| | $ | 2 |
| | $ | 25 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 6 |
|
| | | | | | | | | | | | | | |
| DPL | | | | | | | | | | | | | |
| Letters of credit | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | 4 |
| | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | — |
|
Guaranteed lease residual values(b) | 11 |
| | — |
| | 1 |
| | 1 |
| | 2 |
| | 1 |
| | 6 |
|
| Total commercial commitments | $ | 16 |
| | $ | 3 |
| | $ | 3 |
| | $ | 1 |
| | $ | 2 |
| | $ | 1 |
| | $ | 6 |
|
| | | | | | | | | | | | | | |
| ACE | | | | | | | | | | | | | |
Surety bonds(a) | $ | 3 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Guaranteed lease residual values(b) | 7 |
| | — |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 3 |
|
| Total commercial commitments | $ | 10 |
| | $ | 1 |
| | $ | 3 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 3 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1614 — Commitments and Contingencies
_________
| |
(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 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 $68 million guaranteed by Exelon and PHI, of which $22(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 $74 million guaranteed by Exelon and PHI, of which $25 million, $31 million, and $18 million, $29 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.
|
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 inon the Registrants' financial statements.
MGP Sites (Exelon ComEd, PECO, BGE, PHI and DPL)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 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 leastleast 2025.
•PECO hashas 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 2022.2023.
•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 2021.2023.
•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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1614 — Commitments and Contingencies
As of September 30, 20192020 and December 31, 2018,2019, 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:
| | | | September 30, 2019 | | December 31, 2018 | | September 30, 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 | | 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 | $ | 507 |
|
| $ | 346 |
| | $ | 496 |
|
| $ | 356 |
| Exelon | $ | 494 | | | $ | 320 | | | $ | 478 | | | $ | 320 | |
| Generation | 107 |
| | — |
| | 108 |
| | — |
| Generation | 125 | | | 0 | | | 105 | | | 0 | |
| ComEd | 328 |
| | 327 |
| | 329 |
| | 327 |
| ComEd | 299 | | | 298 | | | 304 | | | 303 | |
| PECO | 20 |
| | 18 |
| | 27 |
| | 25 |
| PECO | 23 | | | 22 | | | 19 | | | 17 | |
| BGE | 3 |
| | 1 |
| | 5 |
| | 4 |
| BGE | 2 | | | 0 | | | 2 | | | 0 | |
| PHI | 49 |
|
| — |
| | 27 |
|
| — |
| PHI | 45 | | | 0 | | | 48 | | | 0 | |
| Pepco | 47 |
| | — |
| | 25 |
| | — |
| Pepco | 43 | | | 0 | | | 46 | | | 0 | |
| DPL | 1 |
| | — |
| | 1 |
| | — |
| DPL | 1 | | | 0 | | | 1 | | | 0 | |
| ACE | 1 |
| | — |
| | 1 |
| | — |
| 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 thea final remedy. The ROD Amendment modified the EPA’sremedy previously proposed plan forselected by EPA in its 2008 ROD. While the ROD required only that the radiological materials and other wastes at the site be capped, the 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 and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in the 2020 - 2021 time frame.by early 2022. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. The EPA has establishedOn October 8, 2019, Cotter (Generation’s indemnitee) provided a deadline of October 2019 for the PRPs to provide anon-binding good faith offer to conduct, or finance, the Remedial Action work. This schedule can be extended by the EPA pending completiona portion of the Remedial Design.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 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.
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 possess 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 RI/FS. The
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1614 — Commitments and Contingencies
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 $20$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 or the extent to which, if 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. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million from all PRPs. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until February 202028, 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 that the PRPs must submit a good faith joint proposed settlement offer by December 1, 2020. 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 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.
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. Once the RI work is completed,In September 2019, Pepco and Generation will issueissued a draft “final” RI report for reviewwhich DOEE approved on February 3, 2020, following a 45-day public comment period and comment by DOEE and the public.a public meeting. Pepco and Generation will then proceed to developare 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 September 16, 2021.
DOEE will then prepare a Proposed Plan and issue a Record of Decision identifying any further response actions determined to be necessary, after considering public comment on the Proposed Plan. 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. 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 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 Road site RI/FS. In addition, the District of Columbia Council directed DOEE to form an official advisory committee made up of members of federal, state, and local environmental regulators, community and
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Commitments and Contingencies
environmental groups, and various academic and technical experts to provide guidance and support to DOEE as the project progressed. This group, called the Anacostia Leadership Council, has met regularly since it was formed. Pepco has participated in the Consultative Working
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 16 — Commitments and Contingencies
Group. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing. The District of Columbia Council has set a deadline of December 31, 2019 for completion of the Record of Decision. An appropriate liability for Pepco’s share of investigation costs has been accrued and is included in the table above.
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 based on DOEE’s stated position following a series of meetings attended by representatives from the Anacostia Leadership Council and the Consultative Working Group. A draft FS,On December 27, 2019, DOEE released for review and comment by the public a Focused Feasibility Study (FFS) and a Proposed Plan (PP), and on September 30, 2020, DOEE released its Interim ROD. The Interim ROD reflects an adaptive management approach which Pepco believes will include the process to identify potential short-term remedies and actions based on the technical findingsrequire several identified “hot spots” in the RI reportriver to be addressed first while continuing to conduct studies and their estimated costs to monitor the extent possible, is being preparedriver 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 is expected later inallows for site specific remediation plans already underway, including the fourth quarter of 2019. DOEE and likely the National Park Service will continue to oversee ongoing remediation efforts and potential longer-term remediesplan for the Anacostia River.Benning Road site to proceed to conclusion. Pepco has concluded that incremental exposure remains reasonably possible, however 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, 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 local Natural Resource Damageremediated. The Trustees who are defined by CERCLA as thecan seek compensation from responsible parties for thesuch damages, including restoration or compensation for any loss of those resources from the environmental contaminants at the site. If natural resources cannot be restored, then compensation for the injury can be sought from the responsible parties.costs. The assessment of Natural Resource Damages (NRD) assessment typically takes place following cleanup because cleanups sometimes also effectively restore habitat.affected natural resources. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of this 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 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 September 30, 20192020 and December 31, 2018,2019, Exelon and Generation had recorded estimated liabilities of approximately $83$91 million and $79$83 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2019,2020, approximately $25$27 millionof this amount related to 257274 open claims presented to Generation, while the remaining $58$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 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.
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 there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Commitments and Contingencies
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,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 16 — Commitmentsresult, the decision is final and Contingencies
itthe case is resolved. It is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement inon June 30, 2020, could be material to Generation’s financial statements.
SubpoenasDeferred 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 U.S. Attorney's Office for the Northern District of IllinoisUSAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it hashad 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 $100 million in August 2020 and $100 million in October 2020. On August 13, 2020, a motion was filed in the U.S. District Court for the Northern District of Illinois by 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 U.S. government and ComEd filed briefs in opposition to this motion. The motion remains pending, and at the U.S. government's direction, the $200 million payment will not be transferred to the U.S. Treasury until the court rules on the motion. $100 million was recorded as Restricted cash and cash equivalents on Exelon’s and ComEd’s Consolidated Balance Sheets as of September 30, 2020 and $100 million was recorded as restricted cash in October 2020.
Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ends 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 and expeditiously with the U.S. Attorney’s Office and the SEC. Exelon and ComEd cannot predict the outcome of the subpoenas orSEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with respect to the SEC investigation.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 two 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.
•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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 14 — Commitments and Contingencies
•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 the CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. The CUB has requested that the court stay the state cases pending the resolution of the federal cases, described below.
•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, the CUB filed a motion to intervene in these cases on October 22, 2020 and filed a proposed complaint against ComEd in conjunction with that motion alleging Racketeer Influenced and Corrupt Organization Act (RICO) and other causes of action on October 29, 2020.
•Two shareholders sent letters to the Exelon Board of Directors in the third quarter of 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.
15. Changes in Accumulated Other Comprehensive Income (Exelon)
The following tables present changes in Exelon's AOCI, net of tax, by component:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2020 | Losses on Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items (a) | | Foreign
Currency
Items | | | | Total |
| Beginning balance | $ | (3) | | | $ | (3,096) | | | $ | (33) | | | | | $ | (3,132) | |
| OCI before reclassifications | (1) | | | (13) | | | 3 | | | | | (11) | |
| Amounts reclassified from AOCI | 0 | | | 39 | | | 0 | | | | | 39 | |
| Net current-period OCI | (1) | | | 26 | | | 3 | | | | | 28 | |
| Ending balance | $ | (4) | | | $ | (3,070) | | | $ | (30) | | | | | $ | (3,104) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2019 | Losses on Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items (a) | | Foreign
Currency
Items | | AOCI of Investments in Unconsolidated Affiliates (b) | | Total |
| Beginning balance | $ | (2) | | | $ | (2,957) | | | $ | (29) | | | $ | (2) | | | $ | (2,990) | |
| OCI before reclassifications | 0 | | | 6 | | | (2) | | | 0 | | | 4 | |
| Amounts reclassified from AOCI | 0 | | | 21 | | | 0 | | | 2 | | | 23 | |
| Net current-period OCI | 0 | | | 27 | | | (2) | | | 2 | | | 27 | |
| Ending balance | $ | (2) | | | $ | (2,930) | | | $ | (31) | | | $ | 0 | | | $ | (2,963) | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 15 — Changes in Accumulated Other Comprehensive Income
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 | Losses on Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items (a) | | Foreign
Currency
Items | | | | Total |
| Beginning balance | $ | (2) | | | $ | (3,165) | | | $ | (27) | | | | | $ | (3,194) | |
| OCI before reclassifications | (2) | | | (17) | | | (3) | | | | | (22) | |
| Amounts reclassified from AOCI | 0 | | | 112 | | | 0 | | | | | 112 | |
| Net current-period OCI | (2) | | | 95 | | | (3) | | | | | 90 | |
| Ending balance | $ | (4) | | | $ | (3,070) | | | $ | (30) | | | | | $ | (3,104) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 | Losses on Cash Flow Hedges | | Pension and Non-Pension Postretirement Benefit Plan Items (a) | | Foreign
Currency
Items | | AOCI of Investments in Unconsolidated Affiliates (b) | | Total |
| Beginning balance | $ | (2) | | | $ | (2,960) | | | $ | (33) | | | $ | 0 | | | $ | (2,995) | |
| OCI before reclassifications | 0 | | | (32) | | | 2 | | | (2) | | | (32) | |
| Amounts reclassified from AOCI | 0 | | | 62 | | | 0 | | | 2 | | | 64 | |
| Net current-period OCI | 0 | | | 30 | | | 2 | | | 0 | | | 32 | |
| Ending balance | $ | (2) | | | $ | (2,930) | | | $ | (31) | | | $ | 0 | | | $ | (2,963) | |
_________
(a)AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 10 — 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.
The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
| Pension and non-pension postretirement benefit plans: | | | | | | | |
| Prior service benefit reclassified to periodic benefit cost | $ | 4 | | | $ | 6 | | | $ | 12 | | | $ | 18 | |
| Actuarial loss reclassified to periodic benefit cost | (16) | | | (13) | | | (50) | | | (39) | |
| Pension and non-pension postretirement benefit plans valuation adjustment | 3 | | | 0 | | | 6 | | | 14 | |
16. Variable Interest Entities (Exelon, Generation, PHI and ACE)
At September 30, 2020 and December 31, 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.
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 September 30, 2020 and December 31, 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 footnote to the table below, are such that creditors, or beneficiaries, do not have recourse to the general credit of Exelon, Generation, PHI, and ACE.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 16 — Variable Interest Entities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2020 | | December 31, 2019 |
| Exelon | | Generation | | PHI (a) | | ACE | | Exelon | | Generation | | PHI (a) | | ACE |
| Cash and cash equivalents | $ | 148 | | | $ | 148 | | | $ | 0 | | | $ | 0 | | | $ | 163 | | | $ | 163 | | | $ | 0 | | | $ | 0 | |
| Restricted cash and cash equivalents | 52 | | | 48 | | | 4 | | | 4 | | | 88 | | | 85 | | | 3 | | | 3 | |
| Accounts receivable | | | | | | | | | | | | | | | |
| Customer | 151 | | | 151 | | | 0 | | | 0 | | | 151 | | | 151 | | | 0 | | | 0 | |
| Other | 39 | | | 39 | | | 0 | | | 0 | | | 39 | | | 39 | | | 0 | | | 0 | |
| Unamortized energy contract assets | 22 | | | 22 | | | 0 | | | 0 | | | 23 | | | 23 | | | 0 | | | 0 | |
| Inventories, net | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Materials and supplies | 241 | | | 241 | | | 0 | | | 0 | | | 227 | | | 227 | | | 0 | | | 0 | |
| Other current assets | 781 | | | 776 | | | 5 | | | 0 | | | 32 | | | 31 | | | 1 | | | 0 | |
| Total current assets | 1,434 | | | 1,425 | | | 9 | | | 4 | | | 723 | | | 719 | | | 4 | | | 3 | |
| Property, plant, and equipment, net | 5,865 | | | 5,865 | | | 0 | | | 0 | | | 6,022 | | | 6,022 | | | 0 | | | 0 | |
| Nuclear decommissioning trust funds | 2,785 | | | 2,785 | | | 0 | | | 0 | | | 2,741 | | | 2,741 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | |
| Unamortized energy contract assets | 253 | | | 253 | | | 0 | | | 0 | | | 250 | | | 250 | | | 0 | | | 0 | |
| Other noncurrent assets | 49 | | | 38 | | | 11 | | | 10 | | | 89 | | | 73 | | | 16 | | | 14 | |
| Total noncurrent assets | 8,952 | | | 8,941 | | | 11 | | | 10 | | | 9,102 | | | 9,086 | | | 16 | | | 14 | |
Total assets (b) | $ | 10,386 | | | $ | 10,366 | | | $ | 20 | | | $ | 14 | | | $ | 9,825 | | | $ | 9,805 | | | $ | 20 | | | $ | 17 | |
| Long-term debt due within one year | $ | 134 | | | $ | 109 | | | $ | 25 | | | $ | 20 | | | $ | 544 | | | $ | 523 | | | $ | 21 | | | $ | 20 | |
| Accounts payable | 81 | | | 81 | | | 0 | | | 0 | | | 106 | | | 106 | | | 0 | | | 0 | |
| Accrued expenses | 63 | | | 63 | | | 0 | | | 0 | | | 70 | | | 70 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | |
| Unamortized energy contract liabilities | 5 | | | 5 | | | 0 | | | 0 | | | 8 | | | 8 | | | 0 | | | 0 | |
| Other current liabilities | 26 | | | 26 | | | 0 | | | 0 | | | 3 | | | 3 | | | 0 | | | 0 | |
| Total current liabilities | 309 | | | 284 | | | 25 | | | 20 | | | 731 | | | 710 | | | 21 | | | 20 | |
| Long-term debt | 913 | | | 906 | | | 7 | | | 6 | | | 527 | | | 504 | | | 23 | | | 21 | |
| Asset retirement obligations | 2,210 | | | 2,210 | | | 0 | | | 0 | | | 2,128 | | | 2,128 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | |
| Unamortized energy contract liabilities | 1 | | | 1 | | | 0 | | | 0 | | | 1 | | | 1 | | | 0 | | | 0 | |
| Other noncurrent liabilities | 106 | | | 106 | | | 0 | | | 0 | | | 89 | | | 89 | | | 0 | | | 0 | |
| Total noncurrent liabilities | 3,230 | | | 3,223 | | | 7 | | | 6 | | | 2,745 | | | 2,722 | | | 23 | | | 21 | |
Total liabilities (c) | $ | 3,539 | | | $ | 3,507 | | | $ | 32 | | | $ | 26 | | | $ | 3,476 | | | $ | 3,432 | | | $ | 44 | | | $ | 41 | |
_________
(a)Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
(b)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 $253 million and $250 million, and other unrestricted assets of $8 million and $0 million as of September 30, 2020 and December 31, 2019, respectively
(c)Exelon’s and Generation’s balances include liabilities with recourse of $8 million and $3 million as of September 30, 2020 and December 31, 2019, respectively.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 16 — Variable Interest Entities
As of September 30, 2020 and December 31, 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 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. See Note 11— Asset Impairments of the Exelon 2019 Form 10-K 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. See Note 5 - Accounts Receivable for 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 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 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 Note 2 - Mergers, Acquisitions and Dispositions of the Exelon 2019 Form 10-K for additional information regarding the Put Option Agreement with EDF.
Exelon and Generation, where indicated, provide the following support to CENG:
•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 18 — Commitments and Contingencies of the Exelon 2019 Form 10-K for more details,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 16 — Variable Interest Entities
•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. 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.
In 2017, Generation’s interests in EGRP were contributed to and are pledged for the ExGen Renewables IV non-recourse debt project financing structure. Refer to Note 12— Debt and Credit Agreements for additional information on ExGen Renewables IV.
As of September 30, 2020 and December 31, 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 September 30, 2020 and December 31, 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 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 16 — Variable Interest Entities
The following table presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2020 | | December 31, 2019 |
| Commercial
Agreement
VIEs | | Equity
Investment
VIEs | | Total | | Commercial
Agreement
VIEs | | Equity
Investment
VIEs | | Total |
Total assets(a) | $ | 736 | | | $ | 409 | | | $ | 1,145 | | | $ | 636 | | | $ | 443 | | | $ | 1,079 | |
Total liabilities(a) | 216 | | | 225 | | | 441 | | | 33 | | | 227 | | | 260 | |
Exelon's ownership interest in VIE(a) | 0 | | | 163 | | | 163 | | | 0 | | | 191 | | | 191 | |
Other ownership interests in VIE(a) | 520 | | | 21 | | | 541 | | | 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 September 30, 2020 and December 31, 2019.
As of September 30, 2020 and December 31, 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. See Note 11— Asset Impairments of the Exelon 2019 Form 10-K 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 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 17 — Supplemental Financial Information
17. 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating revenues |
| Exelon | | Generation | | | | | | | | PHI | | | | DPL | | |
| Three Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 30 | | | $ | 28 | | | | | | | | | $ | 1 | | | | | $ | 1 | | | |
| Variable lease income | 76 | | | 76 | | | | | | | | | 0 | | | | | 0 | | | |
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2019 | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 30 | | | $ | 29 | | | | | | | | | $ | 1 | | | | | $ | 1 | | | |
| Variable lease income | 80 | | | 80 | | | | | | | | | 0 | | | | | 0 | | | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 48 | | | $ | 43 | | | | | | | | | $ | 3 | | | | | $ | 3 | | | |
| Variable lease income | 225 | | | 224 | | | | | | | | | 1 | | | | | 1 | | | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 | | | | | | | | | | | | | | | | |
| Operating lease income | $ | 48 | | | $ | 44 | | | | | | | | | $ | 3 | | | | | $ | 3 | | | |
| Variable lease income | 209 | | | 206 | | | | | | | | | 3 | | | | | 3 | | | |
| | | | | | | | | | | | | | | | | | | | | | Taxes other than income taxes |
| | Taxes other than income | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Three Months Ended September 30, 2020 | | Three Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
Utility taxes(a) | | Utility taxes(a) | $ | 237 | | | $ | 26 | | | $ | 66 | | | $ | 41 | | | $ | 21 | | | $ | 83 | | | $ | 77 | | | $ | 5 | | | $ | 1 | |
| Property | | Property | 152 | | | 66 | | | 7 | | | 4 | | | 42 | | | 32 | | | 21 | | | 10 | | | 1 | |
| Payroll | | Payroll | 59 | | | 29 | | | 7 | | | 4 | | | 4 | | | 6 | | | 2 | | | 1 | | | 1 | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
| Three Months Ended September 30, 2019 | Three Months Ended September 30, 2019 | | | | | | | | | | | | | | | | | Three Months Ended September 30, 2019 | |
Utility taxes(a) | $ | 241 |
| | $ | 29 |
| | $ | 66 |
| | $ | 38 |
| | $ | 21 |
| | $ | 86 |
| | $ | 81 |
| | $ | 5 |
| | $ | — |
| Utility taxes(a) | $ | 241 | | | $ | 29 | | | $ | 66 | | | $ | 38 | | | $ | 21 | | | $ | 86 | | | $ | 81 | | | $ | 5 | | | $ | 0 | |
| Property | 148 |
| | 66 |
| | 7 |
| | 5 |
| | 39 |
| | 31 |
| | 21 |
| | 9 |
| | — |
| Property | 148 | | | 66 | | | 7 | | | 5 | | | 39 | | | 31 | | | 21 | | | 9 | | | 0 | |
| Payroll | 57 |
| | 28 |
| | 7 |
| | 3 |
| | 4 |
| | 6 |
| | 2 |
| | 1 |
| | 1 |
| Payroll | 57 | | | 28 | | | 7 | | | 3 | | | 4 | | | 6 | | | 2 | | | 1 | | | 1 | |
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2018 | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 | | Nine Months Ended September 30, 2020 | |
Utility taxes(a) | $ | 253 |
| | $ | 32 |
| | $ | 67 |
| | $ | 39 |
| | $ | 23 |
| | $ | 92 |
| | $ | 87 |
| | $ | 5 |
| | $ | — |
| Utility taxes(a) | $ | 651 | | | $ | 75 | | | $ | 181 | | | $ | 102 | | | $ | 65 | | | $ | 228 | | | $ | 210 | | | $ | 16 | | | $ | 2 | |
| Property | 145 |
| | 70 |
| | 7 |
| | 4 |
| | 37 |
| | 26 |
| | 16 |
| | 9 |
| | — |
| Property | 449 | | | 199 | | | 23 | | | 12 | | | 121 | | | 94 | | | 63 | | | 29 | | | 2 | |
| Payroll | 58 |
| | 31 |
| | 6 |
| | 3 |
| | 4 |
| | 5 |
| | 1 |
| | 1 |
| | 1 |
| Payroll | 183 | | | 88 | | | 21 | | | 12 | | | 13 | | | 21 | | | 6 | | | 4 | | | 3 | |
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 | Nine Months Ended September 30, 2019 | | | | | | | | | | | | | | | | | Nine Months Ended September 30, 2019 | |
Utility taxes(a) | $ | 672 |
| | $ | 87 |
| | $ | 183 |
| | $ | 102 |
| | $ | 68 |
| | $ | 231 |
| | $ | 217 |
| | $ | 14 |
| | $ | — |
| Utility taxes(a) | $ | 672 | | | $ | 87 | | | $ | 183 | | | $ | 102 | | | $ | 68 | | | $ | 231 | | | $ | 217 | | | $ | 14 | | | $ | 0 | |
| Property | 444 |
| | 205 |
| | 22 |
| | 12 |
| | 114 |
| | 91 |
| | 64 |
| | 25 |
| | 2 |
| Property | 444 | | | 205 | | | 22 | | | 12 | | | 114 | | | 91 | | | 64 | | | 25 | | | 2 | |
| Payroll | 185 |
| | 92 |
| | 21 |
| | 11 |
| | 13 |
| | 20 |
| | 5 |
| | 3 |
| | 2 |
| Payroll | 185 | | | 92 | | | 21 | | | 11 | | | 13 | | | 20 | | | 5 | | | 3 | | | 2 | |
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2018 | | | | | | | | | | | | | | | | | |
Utility taxes(a) | $ | 705 |
| | $ | 92 |
| | $ | 188 |
| | $ | 102 |
| | $ | 70 |
| | $ | 253 |
| | $ | 238 |
| | $ | 15 |
| | $ | — |
| |
| Property | 416 |
| | 204 |
| | 22 |
| | 12 |
| | 106 |
| | 71 |
| | 45 |
| | 24 |
| | 2 |
| |
| Payroll | 191 |
| | 99 |
| | 20 |
| | 11 |
| | 12 |
| | 19 |
| | 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. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 17 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
|
| Other, Net |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Three Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | $ | 50 | | | $ | 50 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Non-regulatory agreement units | 23 | | | 23 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | 398 | | | 398 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Non-regulatory agreement units | 254 | | | 254 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Regulatory offset to NDT fund-related activities(b) | (359) | | | (359) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Decommissioning-related activities | 366 | | | 366 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| AFUDC — Equity | 27 | | | 0 | | | 7 | | | 5 | | | 6 | | | 9 | | | 7 | | | 1 | | | 1 | |
| Non-service net periodic benefit cost | 15 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2019 | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | $ | 67 | | | $ | 67 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Non-regulatory agreement units | 33 | | | 33 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | 89 | | | 89 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Non-regulatory agreement units | 55 | | | 55 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Regulatory offset to NDT fund-related activities(b) | (125) | | | (125) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Decommissioning-related activities | 119 | | | 119 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| AFUDC — Equity | 22 | | | 0 | | | 4 | | | 3 | | | 6 | | | 9 | | | 7 | | | 1 | | | 1 | |
| Non-service net periodic benefit cost | (2) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
134
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Other, Net |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Three Months Ended September 30, 2019 | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | $ | 67 |
| | $ | 67 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Non-regulatory agreement units | 33 |
| | 33 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | 89 |
| | 89 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Non-regulatory agreement units | 55 |
| | 55 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Regulatory offset to NDT fund-related activities(b) | (125 | ) | | (125 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Decommissioning-related activities | 119 |
| | 119 |
| | — |
| | — |
| | — |
|
| — |
| | — |
| | — |
| | — |
|
| AFUDC — Equity | 22 |
| | — |
| | 4 |
| | 3 |
| | 6 |
| | 9 |
| | 7 |
| | 1 |
| | 1 |
|
| Non-service net periodic benefit cost | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2018 | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | $ | 214 |
| | $ | 214 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Non-regulatory agreement units | 58 |
| | 58 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net unrealized (losses) gains on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | (66 | ) | | (66 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Non-regulatory agreement units | 72 |
| | 72 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Regulatory offset to NDT fund-related activities(b) | (110 | ) | | (110 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Decommissioning-related activities | 168 |
| | 168 |
| | — |
| | — |
| | — |
|
| — |
|
| — |
| | — |
| | — |
|
| AFUDC — Equity | 16 |
| | — |
| | 4 |
| | 1 |
| | 5 |
| | 6 |
| | 6 |
| | — |
| | — |
|
| Non-service net periodic benefit cost | (12 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 17 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other, net |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Nine Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | $ | 127 | | | $ | 127 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Non-regulatory agreement units | 127 | | | 127 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | 111 | | | 111 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Non-regulatory agreement units | 1 | | | 1 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Regulatory offset to NDT fund-related activities(b) | (192) | | | (192) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Decommissioning-related activities | 174 | | | 174 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| AFUDC — Equity | 76 | | | 0 | | | 22 | | | 12 | | | 16 | | | 26 | | | 20 | | | 3 | | | 3 | |
| Non-service net periodic benefit cost | 38 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | $ | 197 | | | $ | 197 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Non-regulatory agreement units | 316 | | | 316 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | 565 | | | 565 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Non-regulatory agreement units | 236 | | | 236 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Regulatory offset to NDT fund-related activities(b) | (611) | | | (611) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Decommissioning-related activities | 703 | | | 703 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| AFUDC — Equity | 64 | | | 0 | | | 13 | | | 9 | | | 16 | | | 26 | | | 18 | | | 3 | | | 4 | |
| Non-service net periodic benefit cost | 8 | | | — | | | — | | | — | | | �� | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
__________
(a)Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.
(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 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
135
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Other, Net |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Nine Months Ended September 30, 2019 | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | $ | 197 |
| | $ | 197 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Non-regulatory agreement units | 316 |
| | 316 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | 565 |
| | 565 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Non-regulatory agreement units | 236 |
| | 236 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Regulatory offset to NDT fund-related activities(b) | (611 | ) | | (611 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Decommissioning-related activities | 703 |
| | 703 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| AFUDC — Equity | 64 |
| | — |
| | 13 |
| | 9 |
| | 16 |
| | 26 |
| | 18 |
| | 3 |
| | 4 |
|
| Non-service net periodic benefit cost | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2018 | | | | | | | | | | | | | | | | |
| Decommissioning-related activities: | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | $ | 476 |
| | $ | 476 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Non-regulatory agreement units | 257 |
| | 257 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net unrealized losses on NDT funds | | | | | | | | | | | | | | | | | |
| Regulatory agreement units | (335 | ) | | (335 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Non-regulatory agreement units | (143 | ) | | (143 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Regulatory offset to NDT fund-related activities(b) | (110 | ) | | (110 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Decommissioning-related activities | 145 |
| | 145 |
| | — |
| | — |
| | — |
| | — |
|
| — |
| | — |
| | — |
|
| AFUDC — Equity | 47 |
| | — |
| | 12 |
| | 3 |
| | 13 |
| | 19 |
| | 17 |
| | 2 |
| | — |
|
| Non-service net periodic benefit cost | (33 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
_________
| |
(a) | Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments. |
| |
(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 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for additional information regarding the accounting for nuclear decommissioning. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 17 — Supplemental Financial Information
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 |
| Nine Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
Property, plant, and equipment(a) | $ | 2,831 | | | $ | 1,121 | | | $ | 689 | | | $ | 238 | | | $ | 293 | | | $ | 436 | | | $ | 191 | | | $ | 116 | | | $ | 104 | |
Amortization of regulatory assets(a) | 434 | | | 0 | | | 152 | | | 21 | | | 112 | | | 149 | | | 91 | | | 27 | | | 30 | |
Amortization of intangible assets, net(a) | 47 | | | 40 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Amortization of energy contract assets and liabilities(b) | 24 | | | 22 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Nuclear fuel(c) | 708 | | | 708 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
ARO accretion(d) | 375 | | | 375 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total depreciation, amortization and accretion | $ | 4,419 | | | $ | 2,266 | | | $ | 841 | | | $ | 259 | | | $ | 405 | | | $ | 585 | | | $ | 282 | | | $ | 143 | | | $ | 134 | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 | | | | | | | | | | | | | | | | |
Property, plant, and equipment(a) | $ | 2,803 | | | $ | 1,184 | | | $ | 661 | | | $ | 225 | | | $ | 263 | | | $ | 405 | | | $ | 178 | | | $ | 109 | | | $ | 89 | |
Amortization of regulatory assets(a) | 390 | | | 0 | | | 106 | | | 22 | | | 105 | | | 157 | | | 103 | | | 29 | | | 25 | |
Amortization of intangible assets, net(a) | 44 | | | 37 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Amortization of energy contract assets and liabilities(b) | 14 | | | 14 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Nuclear fuel(c) | 771 | | | 771 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
ARO accretion(d) | 371 | | | 371 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Total depreciation, amortization and accretion | $ | 4,393 | | | $ | 2,377 | | | $ | 767 | | | $ | 247 | | | $ | 368 | | | $ | 562 | | | $ | 281 | | | $ | 138 | | | $ | 114 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Depreciation, amortization and accretion |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Nine Months Ended September 30, 2019 | | | | | | | | | | | | | | | | |
Property, plant and equipment(a) | $ | 2,803 |
| | $ | 1,184 |
| | $ | 661 |
| | $ | 225 |
| | $ | 263 |
| | $ | 405 |
| | $ | 178 |
| | $ | 109 |
| | $ | 89 |
|
Amortization of regulatory assets(a) | 390 |
| | — |
| | 106 |
| | 22 |
| | 105 |
| | 157 |
| | 103 |
| | 29 |
| | 25 |
|
Amortization of intangible assets, net(a) | 44 |
| | 37 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of energy contract assets and liabilities(b) | 14 |
| | 14 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Nuclear fuel(c) | 771 |
| | 771 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
ARO accretion(d) | 371 |
| | 371 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total depreciation, amortization and accretion | $ | 4,393 |
|
| $ | 2,377 |
|
| $ | 767 |
|
| $ | 247 |
|
| $ | 368 |
| | $ | 562 |
| | $ | 281 |
|
| $ | 138 |
|
| $ | 114 |
|
| | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2018 | | | | | | | | | | | | | | | | |
Property, plant and equipment(a) | $ | 2,829 |
| | $ | 1,347 |
| | $ | 613 |
| | $ | 204 |
| | $ | 249 |
| | $ | 355 |
| | $ | 161 |
| | $ | 97 |
| | $ | 70 |
|
Amortization of regulatory assets(a) | 412 |
| | — |
| | 83 |
| | 20 |
| | 109 |
| | 200 |
| | 125 |
| | 38 |
| | 37 |
|
Amortization of intangible assets, net(a) | 43 |
| | 36 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of energy contract assets and liabilities(b) | 8 |
| | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Nuclear fuel(c) | 852 |
| | 852 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
ARO accretion(d) | 367 |
| | 365 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total depreciation, amortization and accretion | $ | 4,511 |
|
| $ | 2,608 |
|
| $ | 696 |
|
| $ | 224 |
|
| $ | 358 |
| | $ | 555 |
| | $ | 286 |
|
| $ | 135 |
|
| $ | 107 |
|
_________(a)Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
| |
(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. |
| |
(d) | Included in Operating and maintenance 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.
(d)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)
Note 17 — Supplemental Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other non-cash operating activities |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Nine Months Ended September 30, 2020 | | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 310 | | | $ | 89 | | | $ | 85 | | | $ | 4 | | | $ | 46 | | | $ | 52 | | | $ | 11 | | | $ | 6 | | | $ | 10 | |
| Provision for uncollectible accounts | 130 | | | 16 | | | 23 | | | 38 | | | 12 | | | 41 | | | 24 | | | 15 | | | 2 | |
Other decommissioning-related activity(a) | (301) | | | (301) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Energy-related options(b) | 79 | | | 79 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
True-up adjustments to decoupling mechanisms and formula rates(c)
| 66 | | | 0 | | | 51 | | | (10) | | | 10 | | | 15 | | | (20) | | | 15 | | | 20 | |
| Severance Costs | 96 | | | 88 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Provision for excess and obsolete inventory | 119 | | | 118 | | | 1 | | | 1 | | | 0 | | | (1) | | | 0 | | | (1) | | | 0 | |
| Long-term incentive plan | (8) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Amortization of operating ROU asset | 185 | | | 135 | | | 1 | | | 0 | | | 23 | | | 21 | | | 5 | | | 6 | | | 2 | |
| | | | | | | | | | | | | | | | | |
Deferred Prosecution Agreement payments(d) | 200 | | | — | | | 200 | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2019 | | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 324 | | | $ | 98 | | | $ | 70 | | | $ | 9 | | | $ | 45 | | | $ | 71 | | | $ | 19 | | | $ | 11 | | | $ | 12 | |
| Provision for uncollectible accounts | 89 | | | 20 | | | 26 | | | 22 | | | 5 | | | 16 | | | 7 | | | 2 | | | 6 | |
Other decommissioning-related activity(a) | (400) | | | (400) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Energy-related options(b) | 21 | | | 21 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
True-up adjustments to decoupling mechanisms and formula rates(e)
| 72 | | | 0 | | | 80 | | | 0 | | | 0 | | | (8) | | | (9) | | | 1 | | | 0 | |
| Long-term incentive plan | 33 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Amortization of operating ROU asset | 193 | | | 138 | | | 2 | | | 0 | | | 23 | | | 26 | | | 6 | | | 7 | | | 4 | |
| Change in environmental liabilities | 23 | | | 0 | | | 0 | | | 0 | | | 0 | | | 23 | | | 23 | | | 0 | | | 0 | |
| | | | | | | | | | | | | | | | | |
| |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
__________
(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 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K 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)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution, energy efficiency, distributed generation, and transmission formula rates. For BGE, Pepco, and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO and ACE, reflects the change in regulatory assets and liabilities associated with their transmission formula rates. See Note 2 — Regulatory Matters for additional information.
(d)See Note 14 — Commitments and Contingencies for additional information related to the Deferred Prosecution Agreement.
(e)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 2 — Regulatory Matters for additional information.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Other non-cash operating activities |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Nine Months Ended September 30, 2019 | | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 324 |
| | $ | 98 |
| | $ | 70 |
| | $ | 9 |
| | $ | 45 |
| | $ | 71 |
| | $ | 19 |
| | $ | 11 |
| | $ | 12 |
|
| Provision for uncollectible accounts | 89 |
| | 20 |
| | 26 |
| | 22 |
| | 5 |
| | 16 |
| | 7 |
| | 2 |
| | 6 |
|
Other decommissioning-related activity(a) | (400 | ) | | (400 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy-related options(b) | 21 |
| | 21 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Amortization of rate stabilization deferral | (8 | ) | | — |
| | — |
| | — |
| | — |
| | (8 | ) | | (9 | ) | | 1 |
| | — |
|
Discrete impacts from EIMA and FEJA(c) | 80 |
| | — |
| | 80 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Long-term incentive plan | 33 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Amortization of operating ROU asset | 193 |
| | 138 |
| | 2 |
| | — |
| | 23 |
| | 26 |
| | 6 |
| | 7 |
| | 4 |
|
| Change in environmental liabilities | 23 |
| | — |
| | — |
| | — |
| | — |
| | 23 |
| | 23 |
| | — |
| | — |
|
| | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2018 | | | | | | | | | | | | | | | | |
| Pension and non-pension postretirement benefit costs | $ | 435 |
| | $ | 151 |
| | $ | 133 |
| | $ | 14 |
| | $ | 43 |
| | $ | 51 |
| | $ | 10 |
| | $ | 5 |
| | $ | 10 |
|
| Provision for uncollectible accounts | 133 |
| | 38 |
| | 30 |
| | 25 |
| | 6 |
| | 32 |
| | 12 |
| | 6 |
| | 14 |
|
Other decommissioning-related activity(a) | (39 | ) | | (39 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy-related options(b) | 4 |
| | 4 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Amortization of rate stabilization deferral | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Discrete impacts from EIMA and FEJA(c) | 27 |
| | — |
| | 27 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Long-term incentive plan | 84 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Asset retirement costs | 20 |
| | — |
| | — |
| | — |
| | — |
| | 20 |
| | 22 |
| | (1 | ) | | (1 | ) |
137
_______
| |
(a) | Includes the elimination of decommissioning-related 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 of the Exelon 2018 Form 10-K 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 in Operating revenues and expenses. |
| |
(c) | Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 6 — Regulatory Matters for additional information. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 17 — Supplemental Financial Information
The following tables provide a reconciliation of cash, 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 |
| September 30, 2020 | | September 30, 2020 | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | Cash and cash equivalents | $ | 1,858 | | | $ | 623 | | | $ | 76 | | | $ | 242 | | | $ | 326 | | | $ | 196 | | | $ | 125 | | | $ | 26 | | | $ | 13 | |
| Restricted cash | | Restricted cash | 485 | | | 100 | | | 305 | | | 7 | | | 1 | | | 38 | | | 33 | | | 0 | | | 4 | |
| Restricted cash included in other long-term assets | | Restricted cash included in other long-term assets | 137 | | | 0 | | | 127 | | | 0 | | | 0 | | | 10 | | | 0 | | | 0 | | | 10 | |
| Total cash, cash equivalents and restricted cash | | Total cash, cash equivalents and restricted cash | $ | 2,480 | | | $ | 723 | | | $ | 508 | | | $ | 249 | | | $ | 327 | | | $ | 244 | | | $ | 158 | | | $ | 26 | | | $ | 27 | |
| | 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 | | Restricted cash | 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, cash equivalents and restricted cash | | Total cash, cash equivalents and restricted cash | $ | 1,122 | | | $ | 449 | | | $ | 403 | | | $ | 27 | | | $ | 25 | | | $ | 181 | | | $ | 63 | | | $ | 13 | | | $ | 28 | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | | | | | | | | | | | | | | | | | |
| September 30, 2019 | | | | | | | | | | | | | | | | | | September 30, 2019 | |
| Cash and cash equivalents | $ | 1,683 |
| | $ | 1,019 |
| | $ | 76 |
| | $ | 224 |
| | $ | 130 |
| | $ | 99 |
| | $ | 18 |
| | $ | 11 |
| | $ | 13 |
| Cash and cash equivalents | $ | 1,683 | | | $ | 1,019 | | | $ | 76 | | | $ | 224 | | | $ | 130 | | | $ | 99 | | | $ | 18 | | | $ | 11 | | | $ | 13 | |
| Restricted cash | 309 |
| | 126 |
| | 124 |
| | 6 |
| | 1 |
| | 38 |
| | 34 |
| | — |
| | 3 |
| Restricted cash | 309 | | | 126 | | | 124 | | | 6 | | | 1 | | | 38 | | | 34 | | | 0 | | | 3 | |
| Restricted cash included in other long-term assets | 186 |
| | — |
| | 171 |
| | — |
| | — |
| | 15 |
| | — |
| | — |
| | 15 |
| Restricted cash included in other long-term assets | 186 | | | 0 | | | 171 | | | 0 | | | 0 | | | 15 | | | 0 | | | 0 | | | 15 | |
| Total cash, cash equivalents and restricted cash | $ | 2,178 |
| | $ | 1,145 |
| | $ | 371 |
| | $ | 230 |
| | $ | 131 |
| | $ | 152 |
| | $ | 52 |
| | $ | 11 |
| | $ | 31 |
| Total cash, cash equivalents and restricted cash | $ | 2,178 | | | $ | 1,145 | | | $ | 371 | | | $ | 230 | | | $ | 131 | | | $ | 152 | | | $ | 52 | | | $ | 11 | | | $ | 31 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2018 | | | | | | | | | | | | | | | | | | 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 | 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, cash equivalents and restricted cash | $ | 1,781 | | | $ | 903 | | | $ | 330 | | | $ | 135 | | | $ | 13 | | | $ | 186 | | | $ | 53 | | | $ | 24 | | | $ | 30 | |
| | | | | | | | | | | | | | | | | | | |
| September 30, 2018 | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 1,918 |
| | $ | 1,187 |
| | $ | 124 |
| | $ | 102 |
| | $ | 113 |
| | $ | 153 |
| | $ | 12 |
| | $ | 110 |
| | $ | 11 |
| |
| Restricted cash | 240 |
| | 152 |
| | 12 |
| | 5 |
| | 3 |
| | 42 |
| | 35 |
| | — |
| | 7 |
| |
| Restricted cash included in other long-term assets | 163 |
| | — |
| | 144 |
| | — |
| | — |
| | 19 |
| | — |
| | — |
| | 19 |
| |
| Total cash, cash equivalents and restricted cash | $ | 2,321 |
| | $ | 1,339 |
| | $ | 280 |
| | $ | 107 |
| | $ | 116 |
| | $ | 214 |
| | $ | 47 |
| | $ | 110 |
| | $ | 37 |
| |
| | | | | | | | | | | | | | | | | | | |
| December 31, 2017 | | | | | | | | | | | | | | | | | | |
| 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 |
| |
For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 20182019 Form 10-K.
Supplemental Balance Sheet Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Unbilled customer revenues |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| September 30, 2019 | $ | 1,256 |
| | $ | 676 |
| | $ | 212 |
| | $ | 102 |
| | $ | 103 |
| | $ | 163 |
| | $ | 91 |
| | $ | 38 |
| | $ | 34 |
|
| December 31, 2018 | 1,656 |
| | 965 |
| | 223 |
| | 114 |
| | 168 |
| | 186 |
| | 97 |
| | 59 |
| | 30 |
|
138
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 17 — Supplemental Financial Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
| | | | | | | | | | | | | | | | | | | | | | Accrued expenses |
| | Accrued expenses | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
| September 30, 2019 | | | | | | | | | | | | | | | | | | |
| September 30, 2020 | | September 30, 2020 | | | | | | | | | | | | | | | | | |
Compensation-related accruals(a) | $ | 880 |
| | $ | 336 |
| | $ | 133 |
| | $ | 48 |
| | $ | 63 |
| | $ | 86 |
| | $ | 26 |
| | $ | 17 |
| | $ | 13 |
| Compensation-related accruals(a) | $ | 898 | | | $ | 352 | | | $ | 147 | | | $ | 60 | | | $ | 72 | | | $ | 95 | | | $ | 31 | | | $ | 16 | | | $ | 14 | |
| Taxes accrued | 431 |
| | 247 |
| | 56 |
| | 13 |
| | 64 |
| | 80 |
| | 61 |
| | 17 |
| | 3 |
| Taxes accrued | 403 | | | 183 | | | 55 | | | 25 | | | 63 | | | 84 | | | 65 | | | 10 | | | 3 | |
| Interest accrued | 421 |
| | 106 |
| | 62 |
| | 33 |
| | 36 |
| | 78 |
| | 37 |
| | 20 |
| | 19 |
| Interest accrued | 440 | | | 79 | | | 64 | | | 36 | | | 40 | | | 80 | | | 38 | | | 21 | | | 21 | |
| | | | | | | | | | | | | | | | | | | |
| December 31, 2018 | | | | | | | | | | | | | | | | | | |
| December 31, 2019 | | December 31, 2019 | |
Compensation-related accruals(a) | $ | 1,191 |
| | $ | 479 |
| | $ | 187 |
| | $ | 49 |
| | $ | 68 |
| | $ | 99 |
| | $ | 29 |
| | $ | 19 |
| | $ | 12 |
| Compensation-related accruals(a) | $ | 1,052 | | | $ | 422 | | | $ | 171 | | | $ | 58 | | | $ | 78 | | | $ | 101 | | | $ | 28 | | | $ | 19 | | | $ | 15 | |
| Taxes accrued | 412 |
| | 226 |
| | 71 |
| | 28 |
| | 46 |
| | 74 |
| | 58 |
| | 4 |
| | 5 |
| Taxes accrued | 414 | | | 222 | | | 83 | | | 3 | | | 26 | | | 117 | | | 90 | | | 14 | | | 8 | |
| Interest accrued | 334 |
| | 77 |
| | 105 |
| | 33 |
| | 39 |
| | 50 |
| | 25 |
| | 8 |
| | 12 |
| Interest accrued | 337 | | | 65 | | | 110 | | | 37 | | | 46 | | | 49 | | | 23 | | | 8 | | | 12 | |
_________ | |
(a) | Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits. |
(a)Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
18. Segment InformationRelated Party Transactions (All Registrants)
Operating segments for eachrevenues from affiliates
Generation
The following table 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:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| Operating revenues from affiliates: | | | | | | | |
ComEd(a)(b) | $ | 71 | | | $ | 83 | | | $ | 241 | | | $ | 266 | |
PECO(c) | 68 | | | 43 | | | 146 | | | 123 | |
BGE(d) | 84 | | | 65 | | | 252 | | | 199 | |
| PHI | 105 | | | 83 | | | 288 | | | 254 | |
Pepco(e) | 80 | | | 66 | | | 219 | | | 188 | |
DPL(f) | 21 | | | 14 | | | 60 | | | 50 | |
ACE(g) | 4 | | | 3 | | | 9 | | | 16 | |
| Other | 3 | | | 1 | | | 5 | | | 2 | |
| Total operating revenues from affiliates (Generation) | $ | 331 | | | $ | 275 | | | $ | 932 | | | $ | 844 | |
__________
(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 the Registrants are determined based on information used by the CODM in deciding how to evaluate performancethree and allocate resources at eachnine months ended September 30, 2020 , respectively, ComEd’s Purchased power from Generation of the Registrants.
Exelon has 11 reportable segments, which include Generation's 5 reportable segments consisting$71 million and $252 million is recorded as Operating revenues from ComEd of the Mid-Atlantic, Midwest, New York, ERCOT$71 million and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, and PHI's 3 reportable segments consisting of Pepco, DPL and ACE. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment,$241 million and as such, no separate segment informationPurchased power and fuel from ComEd of less than $1 million and $11 million at Generation. For the three and nine months ended September 30, 2019 , respectively, ComEd’s Purchased power from Generation of $83 million and $270 million is provided for these Registrants. Exelon,recorded as Operating revenues from ComEd of $83 million and $266 million and as Purchased power and fuel from ComEd of less than $1 million and $4 million at Generation.
(c)Generation provides electric supply to PECO BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resourcesunder contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO 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 5 reportable segments are as follows:
| |
• | Mid-Atlanticsell solar AECs. 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.
|
| |
• | New York represents operations within ISO-NY.
|
| |
• | ERCOT represents operations within Electric Reliability Council of Texas.
|
Other Power Regions:
| |
• | New England represents the operations within ISO-NE.
|
| |
• | South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM.
|
| |
• | West represents operations in the WECC, which includes California ISO.
|
| |
• | Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.
|
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 measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Segment InformationRelated Party Transactions
presentations or deemed more useful than(e)Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the GAAPMDPSC and DCPSC.
(f)Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas 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 provided elsewhere in this report. Generation’s operating revenues include all sales to third partiesregarding BSC and affiliated salesPHISCO.
The following table presents the service company costs allocated 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 results of Generation'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 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 making decisions regarding allocating resources to or assessing the performance of these reportable segments.Registrants:
During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region is no longer regularly reviewed as a separate region by the CODM nor is it presented separately in any external information presented to third parties. Information for the New England region is reviewed by the CODM as part of Other Power Regions. Exelon and Generation retrospectively applied this change.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2019 and 2018 is as follows:
Three Months Ended September 30, 2019 and 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Operating and maintenance from affiliates | | Capitalized costs |
| | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2020 | | 2019 | | 2020 | | 2019 | | 2020 | | 2019 | | 2020 | | 2019 |
| Exelon | | | | | | | | | | | | | | | | |
| BSC | | | | | | | | | | $ | 148 | | | $ | 125 | | | $ | 390 | | | $ | 357 | |
| PHISCO | | | | | | | | | | 15 | | | 16 | | | 45 | | | 57 | |
| Generation | | | | | | | | | | | | | | | | |
| BSC | | $ | 133 | | | $ | 138 | | | $ | 406 | | | $ | 434 | | | 13 | | | 18 | | | 37 | | | 44 | |
| ComEd | | | | | | | | | | | | | | | | |
| BSC | | 65 | | | 72 | | | 204 | | | 195 | | | 49 | | | 37 | | | 133 | | | 98 | |
| PECO | | | | | | | | | | | | | | | | |
| BSC | | 34 | | | 36 | | | 107 | | | 110 | | | 20 | | | 22 | | | 53 | | | 68 | |
| BGE | | | | | | | | | | | | | | | | |
| BSC | | 38 | | | 38 | | | 120 | | | 116 | | | 30 | | | 30 | | | 88 | | | 89 | |
| PHI | | | | | | | | | | | | | | | | |
| BSC | | 36 | | | 35 | | | 107 | | | 102 | | | 36 | | | 18 | | | 79 | | | 58 | |
| PHISCO | | 0 | | | 0 | | | 0 | | | 0 | | | 15 | | | 16 | | | 45 | | | 57 | |
| Pepco | | | | | | | | | | | | | | | | |
| BSC | | 20 | | | 21 | | | 61 | | | 64 | | | 14 | | | 8 | | | 29 | | | 25 | |
| PHISCO | | 28 | | | 29 | | | 90 | | | 92 | | | 7 | | | 8 | | | 20 | | | 26 | |
| | | | | | | | | | | | | | | | |
| DPL | | | | | | | | | | | | | | | | |
| BSC | | 13 | | | 13 | | | 38 | | | 39 | | | 12 | | | 5 | | | 26 | | | 16 | |
| PHISCO | | 24 | | | 24 | | | 73 | | | 74 | | | 4 | | | 4 | | | 13 | | | 16 | |
| | | | | | | | | | | | | | | | |
| ACE | | | | | | | | | | | | | | | | |
| BSC | | 11 | | | 10 | | | 32 | | | 31 | | | 10 | | | 4 | | | 22 | | | 13 | |
| PHISCO | | 21 | | | 22 | | | 65 | | | 67 | | | 4 | | | 4 | | | 12 | | | 15 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Other(b) | | Intersegment
Eliminations | | Exelon |
Operating revenues(c): | | | | | | | | | | | | | | | |
| 2019 |
| Competitive businesses electric revenues | $ | 4,314 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (275 | ) | | $ | 4,039 |
|
| Competitive businesses natural gas revenues | 265 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | 266 |
|
| Competitive businesses other revenues | 195 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | 194 |
|
| Rate-regulated electric revenues | — |
| | 1,583 |
| | 716 |
| | 619 |
| | 1,357 |
| | — |
| | (7 | ) | | 4,268 |
|
| Rate-regulated natural gas revenues | — |
| | — |
| | 62 |
| | 84 |
| | 20 |
| | — |
| | (3 | ) | | 163 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 3 |
| | 474 |
| | (478 | ) | | (1 | ) |
| Total operating revenues | $ | 4,774 |
| | $ | 1,583 |
| | $ | 778 |
| | $ | 703 |
| | $ | 1,380 |
| | $ | 474 |
| | $ | (763 | ) | | $ | 8,929 |
|
140
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Segment InformationRelated Party Transactions
The following tables present current receivables from affiliates and current payables to affiliates:
September 30, 2020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Receivables from affiliates: | | |
| Payables to affiliates: | | Generation | | ComEd | | PECO | | BGE | | | | | | | | ACE | | BSC | | PHISCO | | Other | | Total |
| Generation | | | | $ | 19 | | | $ | 0 | | | $ | 0 | | | | | | | | | $ | 0 | | | $ | 69 | | | $ | 0 | | | $ | 25 | | | $ | 113 | |
| ComEd | | $ | 56 | | (a) | | | 0 | | | 0 | | | | | | | | | 0 | | | 49 | | | 0 | | | 5 | | | 110 | |
| PECO | | 17 | | | 0 | | | | | 0 | | | | | | | | | 0 | | | 24 | | | 0 | | | 6 | | | 47 | |
| BGE | | 8 | | | 0 | | | 0 | | | | | | | | | | | 0 | | | 29 | | | 0 | | | 2 | | | 39 | |
| PHI | | 0 | | | 0 | | | 0 | | | 0 | | | | | | | | | 0 | | | 3 | | | 0 | | | 10 | | | 13 | |
| Pepco | | 13 | | | 0 | | | 0 | | | 0 | | | | | | | | | 0 | | | 16 | | | 12 | | | 2 | | | 43 | |
| DPL | | 2 | | | 0 | | | 0 | | | 0 | | | | | | | | | 0 | | | 11 | | | 9 | | | 1 | | | 23 | |
| ACE | | 4 | | | 0 | | | 0 | | | 0 | | | | | | | | | | | 10 | | | 10 | | | 0 | | | 24 | |
| Other | | 9 | | | 1 | | | 0 | | | 0 | | | | | | | | | 1 | | | 0 | | | 0 | | | | | 11 | |
| Total | | $ | 109 | | | $ | 20 | | | $ | 0 | | | $ | 0 | | | | | | | | | $ | 1 | | | $ | 211 | | | $ | 31 | | | $ | 51 | | | $ | 423 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
__________
(a)As of September 30, 2020 and December 31, 2019, Generation had a contract liability with ComEd for $28 million and $37 million, respectively, that was included in Other current liabilities on Generation’s Consolidated Balance Sheets. At September 30, 2020 and December 31, 2019, ComEd had a Current Payable to Generation of $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.
Borrowings from Exelon/PHI 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. Generation, ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.
Noncurrent Receivables from/Payables to affiliates
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 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for additional information.
The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at Generation:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Other(b) | | Intersegment
Eliminations | | Exelon |
| 2018 |
| Competitive businesses electric revenues | $ | 4,741 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (306 | ) | | $ | 4,435 |
|
| Competitive businesses natural gas revenues | 397 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 397 |
|
| Competitive businesses other revenues | 140 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | 139 |
|
| Rate-regulated electric revenues | — |
| | 1,598 |
| | 700 |
| | 645 |
| | 1,334 |
| | — |
| | (7 | ) | | 4,270 |
|
| Rate-regulated natural gas revenues | — |
| | — |
| | 57 |
| | 86 |
| | 24 |
| | — |
| | (5 | ) | | 162 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 3 |
| | 458 |
| | (461 | ) | | — |
|
| Total operating revenues | $ | 5,278 |
| | $ | 1,598 |
| | $ | 757 |
| | $ | 731 |
| | $ | 1,361 |
| | $ | 458 |
| | $ | (780 | ) | | $ | 9,403 |
|
Intersegment revenues(d): | | | | | | | | | | | | | | | |
| 2019 | $ | 275 |
| | $ | 4 |
| | $ | 1 |
| | $ | 6 |
| | $ | 4 |
| | $ | 474 |
| | $ | (764 | ) | | $ | — |
|
| 2018 | 308 |
| | 4 |
| | 2 |
| | 6 |
| | 3 |
| | 456 |
| | (779 | ) | | — |
|
| Depreciation and amortization: | | | | | | | | | | | | | | | |
| 2019 | $ | 407 |
| | $ | 259 |
| | $ | 83 |
| | $ | 116 |
| | $ | 193 |
| | $ | 25 |
| | $ | — |
| | $ | 1,083 |
|
| 2018 | 468 |
| | 237 |
| | 75 |
| | 110 |
| | 192 |
| | 23 |
| | — |
| | 1,105 |
|
| Operating expenses: | | | | | | | | | | | | | | | |
| 2019 | $ | 4,274 |
| | $ | 1,256 |
| | $ | 595 |
| | $ | 612 |
| | $ | 1,124 |
| | $ | 457 |
| | $ | (759 | ) | | $ | 7,559 |
|
| 2018 | 4,961 |
| | 1,275 |
| | 603 |
| | 628 |
| | 1,116 |
| | 459 |
| | (790 | ) | | 8,252 |
|
| Interest expense, net: | | | | | | | | | | | | | | | |
| 2019 | $ | 109 |
| | $ | 91 |
| | $ | 33 |
| | $ | 31 |
| | $ | 66 |
| | $ | 79 |
| | $ | — |
| | $ | 409 |
|
| 2018 | 101 |
| | 85 |
| | 32 |
| | 27 |
| | 65 |
| | 83 |
| | — |
| | 393 |
|
| Income (loss) before income taxes: | | | | | | | | | | | | | | | |
| 2019 | $ | 501 |
| | $ | 245 |
| | $ | 154 |
| | $ | 67 |
| | $ | 203 |
| | $ | (68 | ) | | $ | — |
| | $ | 1,102 |
|
| 2018 | 389 |
| | 245 |
| | 124 |
| | 81 |
| | 191 |
| | (83 | ) | | — |
| | 947 |
|
| Income Taxes: | | | | | | | | | | | | | | | |
| 2019 | $ | 87 |
| | $ | 45 |
| | $ | 14 |
| | $ | 12 |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 172 |
|
| 2018 | 78 |
| | 52 |
| | (2 | ) | | 18 |
| | 4 |
| | (13 | ) | | — |
| | 137 |
|
| Net income (loss): | | | | | | | | | | | | | | |
|
| 2019 | $ | 244 |
| | $ | 200 |
| | $ | 140 |
| | $ | 55 |
| | $ | 189 |
| | $ | (68 | ) | | $ | — |
| | $ | 760 |
|
| 2018 | 300 |
| | 193 |
| | 126 |
| | 63 |
| | 187 |
| | (69 | ) | | — |
| | 800 |
|
| Capital Expenditures | | | | | | | | | | | | | | | |
| 2019 | $ | 392 |
| | $ | 452 |
| | $ | 228 |
| | $ | 300 |
| | $ | 308 |
| | $ | 7 |
| | $ | — |
| | $ | 1,687 |
|
| 2018 | 362 |
| | 514 |
| | 204 |
| | 233 |
| | 359 |
| | 18 |
| | — |
| | 1,690 |
|
141
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Segment InformationRelated Party Transactions
| | | | | | | | | | | |
| September 30, 2020 | | December 31, 2019 |
| ComEd | $ | 2,445 | | | $ | 2,622 | |
| PECO | 443 | | | 480 | |
| Other | 0 | | | 1 | |
| Total: | $ | 2,888 | | | $ | 3,103 | |
__________Long-term debt to financing trusts
| |
(a) | Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $43 million, sales to BGE of $65 million, sales to Pepco of $65 million, sales to DPL of $14 million and sales to ACE of $3 million in the Mid-Atlantic region, and sales to ComEd of $83 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $35 million, sales to BGE of $69 million, sales to Pepco of $46 million, sales to DPL of $26 million and sales to ACE of $10 million in the Mid-Atlantic region, and sales to ComEd of $122 million in the Midwest region, which eliminate upon consolidation. |
| |
(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 17 — 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 accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. |
The following table presents Long-term debt to financing trusts:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2020 | | December 31, 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
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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
(Dollars in millions except per share data, unless otherwise noted)
Note 18 — Segment Information
PHI:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pepco | | DPL | | ACE | | Other(b) | | Intersegment
Eliminations | | PHI |
Operating revenues(a): |
| 2019 | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 642 |
| | $ | 299 |
| | $ | 419 |
| | $ | — |
| | $ | (3 | ) | | $ | 1,357 |
|
| Rate-regulated natural gas revenues | — |
| | 20 |
| | — |
| | — |
| | — |
| | 20 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | 92 |
| | (89 | ) | | 3 |
|
| Total operating revenues | $ | 642 |
| | $ | 319 |
| | $ | 419 |
| | $ | 92 |
| | $ | (92 | ) | | $ | 1,380 |
|
| 2018 | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 628 |
| | $ | 304 |
| | $ | 406 |
| | $ | — |
| | $ | (4 | ) | | $ | 1,334 |
|
| Rate-regulated natural gas revenues | — |
| | 24 |
| | — |
| | — |
| | — |
| | 24 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | 103 |
| | (100 | ) | | 3 |
|
| Total operating revenues | $ | 628 |
| | $ | 328 |
| | $ | 406 |
| | $ | 103 |
| | $ | (104 | ) | | $ | 1,361 |
|
| Intersegment revenues: | | | | | | | | | | | |
| 2019 | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 93 |
| | $ | (93 | ) | | $ | 4 |
|
| 2018 | 2 |
| | 2 |
| | 1 |
| | 103 |
| | (105 | ) | | 3 |
|
| Depreciation and amortization: | | | | | | | | | | | |
| 2019 | $ | 95 |
| | $ | 46 |
| | $ | 43 |
| | $ | 9 |
| | $ | — |
| | $ | 193 |
|
| 2018 | 99 |
| | 47 |
| | 38 |
| | 8 |
| | — |
| | 192 |
|
| Operating expenses: | | | | | | | | | | | |
| 2019 | $ | 515 |
| | $ | 268 |
| | $ | 340 |
| | $ | 95 |
| | $ | (94 | ) | | $ | 1,124 |
|
| 2018 | 516 |
| | 277 |
| | 322 |
| | 105 |
| | (104 | ) | | 1,116 |
|
| Interest expense, net: | | | | | | | | | | | |
| 2019 | $ | 33 |
| | $ | 15 |
| | $ | 15 |
| | $ | 3 |
| | $ | — |
| | $ | 66 |
|
| 2018 | 32 |
| | 15 |
| | 16 |
| | 2 |
| | — |
| | 65 |
|
| Income (loss) before income taxes: | | | | | | | | | | | |
| 2019 | $ | 103 |
| | $ | 38 |
| | $ | 65 |
| | $ | 192 |
| | $ | (195 | ) | | $ | 203 |
|
| 2018 | 87 |
| | 38 |
| | 69 |
| | 179 |
| | (182 | ) | | 191 |
|
| Income Taxes: | | | | | | | | | | | |
| 2019 | $ | 5 |
| | $ | 5 |
| | $ | 2 |
| | $ | 3 |
| | $ | (1 | ) | | $ | 14 |
|
| 2018 | (2 | ) | | 5 |
| | 8 |
| | (8 | ) | | 1 |
| | 4 |
|
| Net income (loss): | | | | | | | | | | | |
| 2019 | $ | 98 |
| | $ | 33 |
| | $ | 63 |
| | $ | (9 | ) | | $ | 4 |
| | $ | 189 |
|
| 2018 | 89 |
| | 33 |
| | 61 |
| | 1 |
| | 3 |
| | 187 |
|
| Capital Expenditures | | | | | | | | | | | |
| 2019 | $ | 157 |
| | $ | 85 |
| | $ | 73 |
| | $ | (7 | ) | | $ | — |
| | $ | 308 |
|
| 2018 | 188 |
| | 88 |
| | 77 |
| | 6 |
| | — |
| | 359 |
|
__________
| |
(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 17 — 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. |
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Segment Information
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):
|
| | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2019 |
| | Revenues from external customers(a) | | Intersegment
revenues |
| Total
Revenues |
| | Contracts with customers | | Other(b) | | Total | | |
| Mid-Atlantic | $ | 1,351 |
| | $ | 10 |
| | $ | 1,361 |
| | $ | 3 |
| | $ | 1,364 |
|
| Midwest | 1,052 |
| | 47 |
| | 1,099 |
| | (17 | ) | | 1,082 |
|
| New York | 414 |
| | 15 |
| | 429 |
| | — |
| | 429 |
|
| ERCOT | 288 |
| | 72 |
| | 360 |
| | 5 |
| | 365 |
|
| Other Power Regions | 873 |
| | 192 |
| | 1,065 |
| | (25 | ) | | 1,040 |
|
| Total Competitive Businesses Electric Revenues | 3,978 |
| | 336 |
| | 4,314 |
| | (34 | ) | | 4,280 |
|
| Competitive Businesses Natural Gas Revenues | 160 |
| | 105 |
| | 265 |
| | 34 |
| | 299 |
|
Competitive Businesses Other Revenues(c) | 112 |
| | 83 |
| | 195 |
| | — |
| | 195 |
|
| Total Generation Consolidated Operating Revenues | $ | 4,250 |
| | $ | 524 |
| | $ | 4,774 |
| | $ | — |
| | $ | 4,774 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2018 |
| | Revenues from external customers(a) | | Intersegment
revenues | | Total
Revenues |
| | Contracts with customers | | Other(b) | | Total | | |
| Mid-Atlantic | $ | 1,397 |
| | $ | 52 |
| | $ | 1,449 |
| | $ | 7 |
| | $ | 1,456 |
|
| Midwest | 1,095 |
| | 26 |
| | 1,121 |
| | (4 | ) | | 1,117 |
|
| New York | 475 |
| | (6 | ) | | 469 |
| | — |
| | 469 |
|
| ERCOT | 156 |
| | 289 |
| | 445 |
| | (1 | ) | | 444 |
|
| Other Power Regions | 959 |
| | 298 |
| | 1,257 |
| | (45 | ) | | 1,212 |
|
| Total Competitive Businesses Electric Revenues | 4,082 |
| | 659 |
| | 4,741 |
| | (43 | ) | | 4,698 |
|
| Competitive Businesses Natural Gas Revenues | 200 |
| | 197 |
| | 397 |
| | 43 |
| | 440 |
|
Competitive Businesses Other Revenues(c) | 130 |
| | 10 |
| | 140 |
| | — |
| | 140 |
|
| Total Generation Consolidated Operating Revenues | $ | 4,412 |
| | $ | 866 |
| | $ | 5,278 |
| | $ | — |
| | $ | 5,278 |
|
__________
| |
(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 unrealized mark-to-market gains of $77 million and $6 million in 2019 and 2018, respectively, and elimination of intersegment revenues. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Segment Information
Revenues net of purchased power and fuel expense (Generation):
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2019 | | Three Months Ended September 30, 2018 |
| | RNF
from external
customers(a) | | Intersegment RNF | | Total RNF | | RNF
from external
customers(a) | | Intersegment RNF | | Total RNF |
| Mid-Atlantic | $ | 684 |
| | $ | 5 |
| | $ | 689 |
| | $ | 746 |
| | $ | 17 |
| | $ | 763 |
|
| Midwest | 763 |
| | (16 | ) | | 747 |
| | 763 |
| | 5 |
| | 768 |
|
| New York | 288 |
| | 3 |
| | 291 |
| | 290 |
| | 2 |
| | 292 |
|
| ERCOT | 76 |
| | (4 | ) | | 72 |
| | 161 |
| | (63 | ) | | 98 |
|
| Other Power Regions | 212 |
| | (28 | ) | | 184 |
| | 226 |
| | (46 | ) | | 180 |
|
| Total Revenues net of purchased power and fuel for Reportable Segments | 2,023 |
|
| (40 | ) |
| 1,983 |
|
| 2,186 |
|
| (85 | ) |
| 2,101 |
|
Other(b) | 100 |
| | 40 |
| | 140 |
| | 112 |
| | 85 |
| | 197 |
|
| Total Generation Revenues net of purchased power and fuel expense | $ | 2,123 |
|
| $ | — |
|
| $ | 2,123 |
|
| $ | 2,298 |
|
| $ | — |
|
| $ | 2,298 |
|
__________
| |
(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 unrealized mark-to-market gains of $17 million and $71 million in 2019 and 2018, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of $3 million and $18 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Segment Information
Electric and Gas Revenue by Customer Class (Utility Registrants):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2019 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 865 |
| | $ | 479 |
| | $ | 352 |
| | $ | 741 |
| | $ | 311 |
| | $ | 178 |
| | $ | 252 |
|
| Small commercial & industrial | 393 |
| | 109 |
| | 64 |
| | 147 |
| | 41 |
| | 48 |
| | 58 |
|
| Large commercial & industrial | 141 |
| | 63 |
| | 116 |
| | 297 |
| | 222 |
| | 26 |
| | 49 |
|
| Public authorities & electric railroads | 12 |
| | 9 |
| | 7 |
| | 17 |
| | 11 |
| | 3 |
| | 3 |
|
Other(a) | 222 |
| | 63 |
| | 82 |
| | 164 |
| | 58 |
| | 50 |
| | 56 |
|
Total rate-regulated electric revenues(b) | $ | 1,633 |
| | $ | 723 |
| | $ | 621 |
| | $ | 1,366 |
| | $ | 643 |
| | $ | 305 |
| | $ | 418 |
|
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | — |
| | $ | 38 |
| | $ | 49 |
| | $ | 9 |
| | $ | — |
| | $ | 9 |
| | $ | — |
|
| Small commercial & industrial | — |
| | 17 |
| | 9 |
| | 4 |
| | — |
| | 4 |
| | — |
|
| Large commercial & industrial | — |
| | — |
| | 20 |
| | 1 |
| | — |
| | 1 |
| | — |
|
| Transportation | — |
| | 5 |
| | — |
| | 4 |
| | — |
| | 4 |
| | — |
|
Other(c) | — |
| | 2 |
| | 5 |
| | 2 |
| | — |
| | 2 |
| | — |
|
Total rate-regulated natural gas revenues(d) | $ | — |
| | $ | 62 |
| | $ | 83 |
| | $ | 20 |
| | $ | — |
| | $ | 20 |
| | $ | — |
|
| Total rate-regulated revenues from contracts with customers | $ | 1,633 |
| | $ | 785 |
| | $ | 704 |
| | $ | 1,386 |
| | $ | 643 |
| | $ | 325 |
| | $ | 418 |
|
| | | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (56 | ) | | $ | (11 | ) | | $ | (5 | ) | | $ | (9 | ) | | $ | (3 | ) | | $ | (6 | ) | | $ | 1 |
|
Other rate-regulated electric revenues(e) | 6 |
| | 4 |
| | 3 |
| | 3 |
| | 2 |
| | — |
| | — |
|
Other rate-regulated natural gas revenues(e) | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
|
| Total other revenues | $ | (50 | ) | | $ | (7 | ) | | $ | (1 | ) | | $ | (6 | ) | | $ | (1 | ) | | $ | (6 | ) | | $ | 1 |
|
| Total rate-regulated revenues for reportable segments | $ | 1,583 |
| | $ | 778 |
| | $ | 703 |
| | $ | 1,380 |
| | $ | 642 |
| | $ | 319 |
| | $ | 419 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Segment Information
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2018 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 861 |
| | $ | 458 |
| | $ | 366 |
| | $ | 726 |
| | $ | 306 |
| | $ | 180 |
| | $ | 240 |
|
| Small commercial & industrial | 391 |
| | 108 |
| | 68 |
| | 140 |
| | 39 |
| | 48 |
| | 53 |
|
| Large commercial & industrial | 131 |
| | 64 |
| | 117 |
| | 303 |
| | 230 |
| | 25 |
| | 48 |
|
| Public authorities & electric railroads | 11 |
| | 7 |
| | 7 |
| | 14 |
| | 8 |
| | 3 |
| | 3 |
|
Other(a) | 212 |
| | 59 |
| | 91 |
| | 156 |
| | 47 |
| | 47 |
| | 63 |
|
Total rate-regulated electric revenues(b) | $ | 1,606 |
| | $ | 696 |
| | $ | 649 |
| | $ | 1,339 |
| | $ | 630 |
| | $ | 303 |
| | $ | 407 |
|
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | $ | — |
| | $ | 36 |
| | $ | 46 |
| | $ | 8 |
| | $ | — |
| | $ | 8 |
| | $ | — |
|
| Small commercial & industrial | — |
| | 15 |
| | 8 |
| | 5 |
| | — |
| | 5 |
| | — |
|
| Large commercial & industrial | — |
| | — |
| | 17 |
| | 2 |
| | — |
| | 2 |
| | — |
|
| Transportation | — |
| | 5 |
| | — |
| | 3 |
| | — |
| | 3 |
| | — |
|
Other(c) | — |
| | 1 |
| | 12 |
| | 6 |
| | — |
| | 6 |
| | — |
|
Total rate-regulated natural gas revenues(d) | $ | — |
| | $ | 57 |
| | $ | 83 |
| | $ | 24 |
| | $ | — |
| | $ | 24 |
| | $ | — |
|
| Total rate-regulated revenues from contracts with customers | $ | 1,606 |
| | $ | 753 |
| | $ | 732 |
| | $ | 1,363 |
| | $ | 630 |
| | $ | 327 |
| | $ | 407 |
|
| | | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (15 | ) | | $ | 1 |
| | $ | (6 | ) | | $ | (5 | ) | | $ | (4 | ) | | $ | — |
| | $ | (1 | ) |
Other rate-regulated electric revenues(e) | 7 |
| | 3 |
| | 4 |
| | 3 |
| | 2 |
| | 1 |
| | — |
|
Other rate-regulated natural gas revenues(e) | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
|
| Total other revenues | $ | (8 | ) | | $ | 4 |
| | $ | (1 | ) | | $ | (2 | ) | | $ | (2 | ) | | $ | 1 |
| | $ | (1 | ) |
| Total rate-regulated revenues for reportable segments | $ | 1,598 |
| | $ | 757 |
| | $ | 731 |
| | $ | 1,361 |
| | $ | 628 |
| | $ | 328 |
| | $ | 406 |
|
__________
| |
(a) | Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue. |
| |
(b) | Includes operating revenues from affiliates of $4 million, $1 million, $2 million, $4 million, $2 million, $1 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $4 million, $2 million, $1 million, $3 million $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018. |
| |
(c) | Includes revenues from off-system natural gas sales. |
| |
(d) | Includes operating revenues from affiliates of less than $1 million and $4 million at PECO and BGE, respectively, in 2019 and less than $1 million and $5 million at PECO and BGE, respectively, in 2018. |
| |
(e) | Includes late payment charge revenues. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Segment Information
Nine Months Ended September 30, 2019 and 2018
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Other(b) | | Intersegment
Eliminations | | Exelon |
Operating revenues(c): |
| 2019 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 12,365 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (840 | ) | | $ | 11,525 |
|
| Competitive businesses natural gas revenues | 1,479 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,479 |
|
| Competitive businesses other revenues | 436 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (4 | ) | | 432 |
|
| Rate-regulated electric revenues | — |
| | 4,342 |
| | 1,901 |
| | 1,817 |
| | 3,574 |
| | — |
| | (25 | ) | | 11,609 |
|
| Rate-regulated natural gas revenues | — |
| | — |
| | 432 |
| | 510 |
| | 116 |
| | — |
| | (12 | ) | | 1,046 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 10 |
| | 1,410 |
| | (1,415 | ) | | 5 |
|
| Total operating revenues | $ | 14,280 |
| | $ | 4,342 |
| | $ | 2,333 |
| | $ | 2,327 |
| | $ | 3,700 |
| | $ | 1,410 |
| | $ | (2,296 | ) | | $ | 26,096 |
|
| 2018 | | | | | | | | | | | | | | | |
| Competitive businesses electric revenues | $ | 13,190 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (969 | ) | | $ | 12,221 |
|
| Competitive businesses natural gas revenues | 1,839 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (8 | ) | | 1,831 |
|
| Competitive businesses other revenues | 339 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (4 | ) | | 335 |
|
| Rate-regulated electric revenues | — |
| | 4,508 |
| | 1,893 |
| | 1,850 |
| | 3,549 |
| | — |
| | (34 | ) | | 11,766 |
|
| Rate-regulated natural gas revenues | — |
| | — |
| | 382 |
| | 519 |
| | 129 |
| | — |
| | (13 | ) | | 1,017 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 10 |
| | 1,398 |
| | (1,408 | ) | | — |
|
| Total operating revenues | $ | 15,368 |
| | $ | 4,508 |
| | $ | 2,275 |
| | $ | 2,369 |
| | $ | 3,688 |
| | $ | 1,398 |
| | $ | (2,436 | ) | | $ | 27,170 |
|
| Shared service and other revenues | | | | | | | | | | | | | | | |
Intersegment revenues(d): | | | | | | | | | | | | | | | |
| 2019 | $ | 844 |
| | $ | 13 |
| | $ | 4 |
| | $ | 18 |
| | $ | 11 |
| | $ | 1,410 |
| | $ | (2,300 | ) | | $ | — |
|
| 2018 | 981 |
| | 23 |
| | 5 |
| | 18 |
| | 11 |
| | 1,392 |
| | (2,430 | ) | | — |
|
| Depreciation and amortization: | | | | | | | | | | | | | | | |
| 2019 | $ | 1,221 |
| | $ | 767 |
| | $ | 247 |
| | $ | 368 |
| | $ | 562 |
| | $ | 72 |
| | $ | — |
| | $ | 3,237 |
|
| 2018 | 1,383 |
| | 696 |
| | 224 |
| | 358 |
| | 555 |
| | 68 |
| | — |
| | 3,284 |
|
| Operating expenses: | | | | | | | | | | | | | | | |
| 2019 | $ | 13,333 |
| | $ | 3,431 |
| | $ | 1,783 |
| | $ | 1,936 |
| | $ | 3,106 |
| | $ | 1,405 |
| | $ | (2,291 | ) | | $ | 22,703 |
|
| 2018 | 14,475 |
| | 3,610 |
| | 1,853 |
| | 2,005 |
| | 3,165 |
| | 1,395 |
| | (2,467 | ) | | 24,036 |
|
| Interest expense, net: | | | | | | | | | | | | | | | |
| 2019 | $ | 336 |
| | $ | 268 |
| | $ | 100 |
| | $ | 89 |
| | $ | 197 |
| | $ | 231 |
| | $ | — |
| | $ | 1,221 |
|
| 2018 | 305 |
| | 261 |
| | 96 |
| | 78 |
| | 193 |
| | 205 |
| | — |
| | 1,138 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Segment Information
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation(a) | | ComEd | | PECO | | BGE | | PHI | | Other(b) | | Intersegment
Eliminations | | Exelon |
| Income (loss) before income taxes: | | | | | | | | | | | | | | | |
| 2019 | $ | 1,355 |
| | $ | 674 |
| | $ | 461 |
| | $ | 320 |
| | $ | 436 |
| | $ | (218 | ) | | $ | — |
| | $ | 3,028 |
|
| 2018 | 800 |
| | 663 |
| | 331 |
| | 301 |
| | 363 |
| | (195 | ) | | — |
| | 2,263 |
|
| Income Taxes: | | | | | | | | | | | | | | | |
| 2019 | $ | 388 |
| | $ | 130 |
| | $ | 51 |
| | $ | 59 |
| | $ | 25 |
| | $ | (27 | ) | | $ | — |
| | $ | 626 |
|
| 2018 | 110 |
| | 140 |
| | (5 | ) | | 59 |
| | 28 |
| | (70 | ) | | — |
| | 262 |
|
| Net income (loss): | | | | | | | | | | | | | | | |
| 2019 | $ | 784 |
| | $ | 544 |
| | $ | 410 |
| | $ | 261 |
| | $ | 412 |
| | $ | (191 | ) | | $ | — |
| | $ | 2,220 |
|
| 2018 | 667 |
| | 523 |
| | 336 |
| | 242 |
| | 336 |
| | (125 | ) | | — |
| | 1,979 |
|
| Capital Expenditures | | | | | | | | | | | | | | | |
| 2019 | $ | 1,282 |
| | $ | 1,413 |
| | $ | 675 |
| | $ | 842 |
| | $ | 1,006 |
| | $ | 41 |
| | $ | — |
| | $ | 5,259 |
|
| 2018 | 1,660 |
| | 1,540 |
| | 615 |
| | 667 |
| | 988 |
| | 27 |
| | — |
| | 5,497 |
|
| Total assets: | | | | | | | | | | | | | | | |
| September 30, 2019 | $ | 47,984 |
| | $ | 32,326 |
| | $ | 11,379 |
| | $ | 10,304 |
| | $ | 22,576 |
| | $ | 8,254 |
| | $ | (10,085 | ) | | $ | 122,738 |
|
| December 31, 2018 | 47,556 |
| | 31,213 |
| | 10,642 |
| | 9,716 |
| | 21,984 |
| | 8,355 |
| | (9,800 | ) | | 119,666 |
|
__________
| |
(a) | Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $123 million, sales to BGE of $199 million, sales to Pepco of $188 million, sales to DPL of $50 million and sales to ACE of $16 million in the Mid-Atlantic region, and sales to ComEd of $266 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $97 million, sales to BGE of $198 million, sales to Pepco of $143 million, sales to DPL of $103 million and sales to ACE of $21 million in the Mid-Atlantic region, and sales to ComEd of $419 million in the Midwest region, which eliminate upon consolidation. |
| |
(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 17 — 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 accounting guidance. For Exelon, these amounts are included in Operating revenues in the 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 18 — Segment Information
PHI:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pepco | | DPL | | ACE | | Other(b) | | Intersegment
Eliminations | | PHI |
Operating revenues(a): | | | | | | | | | | | |
| 2019 | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 1,748 |
| | $ | 871 |
| | $ | 966 |
| | $ | (1 | ) | | $ | (10 | ) | | $ | 3,574 |
|
| Rate-regulated natural gas revenues | — |
| | 116 |
| | — |
| | — |
| | — |
| | 116 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | 298 |
| | (288 | ) | | 10 |
|
| Total operating revenues | $ | 1,748 |
| | $ | 987 |
| | $ | 966 |
| | $ | 297 |
| | $ | (298 | ) | | $ | 3,700 |
|
| 2018 | | | | | | | | | | | |
| Rate-regulated electric revenues | $ | 1,708 |
| | $ | 872 |
| | $ | 981 |
| | $ | — |
| | $ | (12 | ) | | $ | 3,549 |
|
| Rate-regulated natural gas revenues | — |
| | 129 |
| | — |
| | — |
| | — |
| | 129 |
|
| Shared service and other revenues | — |
| | — |
| | — |
| | 326 |
| | (316 | ) | | 10 |
|
| Total operating revenues | $ | 1,708 |
| | $ | 1,001 |
| | $ | 981 |
| | $ | 326 |
| | $ | (328 | ) | | $ | 3,688 |
|
| Intersegment revenues: | | | | | | | | | | | |
| 2019 | $ | 5 |
| | $ | 5 |
| | $ | 2 |
| | $ | 297 |
| | $ | (298 | ) | | $ | 11 |
|
| 2018 | 5 |
| | 6 |
| | 2 |
| | 325 |
| | (327 | ) | | 11 |
|
| Depreciation and amortization: | | | | | | | | | | | |
| 2019 | $ | 281 |
| | $ | 138 |
| | $ | 114 |
| | $ | 29 |
| | $ | — |
| | $ | 562 |
|
| 2018 | 286 |
| | 135 |
| | 107 |
| | 27 |
| | — |
| | 555 |
|
| Operating expenses: | | | | | | | | | | | |
| 2019 | $ | 1,444 |
| | $ | 820 |
| | $ | 838 |
| | $ | 302 |
| | $ | (298 | ) | | $ | 3,106 |
|
| 2018 | 1,454 |
| | 859 |
| | 847 |
| | 329 |
| | (324 | ) | | 3,165 |
|
| Interest expense, net: | | | | | | | | | | | |
| 2019 | $ | 100 |
| | $ | 45 |
| | $ | 44 |
| | $ | 8 |
| | $ | — |
| | $ | 197 |
|
| 2018 | 96 |
| | 42 |
| | 48 |
| | 7 |
| | — |
| | 193 |
|
| Income (loss) before income taxes: | | | | | | | | | | | |
| 2019 | $ | 226 |
| | $ | 132 |
| | $ | 89 |
| | $ | 411 |
| | $ | (422 | ) | | $ | 436 |
|
| 2018 | 181 |
| | 107 |
| | 88 |
| | 326 |
| | (339 | ) | | 363 |
|
| Income Taxes: | | | | | | | | | | | |
| 2019 | $ | 9 |
| | $ | 16 |
| | $ | 2 |
| | $ | (1 | ) | | $ | (1 | ) | | $ | 25 |
|
| 2018 | 7 |
| | 17 |
| | 12 |
| | (8 | ) | | — |
| | 28 |
|
| Net income (loss): | | | | | | | | | | | |
| 2019 | $ | 217 |
| | $ | 116 |
| | $ | 87 |
| | $ | (19 | ) | | $ | 11 |
| | $ | 412 |
|
| 2018 | 174 |
| | 90 |
| | 76 |
| | (15 | ) | | 11 |
| | 336 |
|
| Capital Expenditures | | | | | | | | | | | |
| 2019 | $ | 455 |
| | $ | 245 |
| | $ | 300 |
| | $ | 6 |
| | $ | — |
| | $ | 1,006 |
|
| 2018 | 475 |
| | 254 |
| | 247 |
| | 12 |
| | — |
| | 988 |
|
| Total assets: | | | | | | | | | | | |
| September 30, 2019 | $ | 8,603 |
| | $ | 4,724 |
| | $ | 3,916 |
| | $ | 11,071 |
| | $ | (5,738 | ) | | $ | 22,576 |
|
| December 31, 2018 | 8,299 |
| | 4,588 |
| | 3,699 |
| | 10,819 |
| | (5,421 | ) | | 21,984 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Segment Information
__________
| |
(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 17 — 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. |
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):
|
| | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 |
| | Revenues from external customers(a) | | Intersegment Revenues | | Total Revenues |
| | Contracts with customers | | Other(b) | | Total | | |
| Mid-Atlantic | $ | 3,798 |
| | $ | 9 |
| | $ | 3,807 |
| | $ | 2 |
| | $ | 3,809 |
|
| Midwest | 3,083 |
| | 172 |
| | 3,255 |
| | (31 | ) | | 3,224 |
|
| New York | 1,195 |
| | 16 |
| | 1,211 |
| | — |
| | 1,211 |
|
| ERCOT | 594 |
| | 198 |
| | 792 |
| | 13 |
| | 805 |
|
| Other Power Regions | 2,849 |
| | 451 |
| | 3,300 |
| | (46 | ) | | 3,254 |
|
| Total Competitive Businesses Electric Revenues | 11,519 |
| | 846 |
| | 12,365 |
| | (62 | ) | | 12,303 |
|
| Competitive Businesses Natural Gas Revenues | 1,041 |
| | 438 |
| | 1,479 |
| | 62 |
| | 1,541 |
|
Competitive Businesses Other Revenues(c) | 343 |
| | 93 |
| | 436 |
| | — |
| | 436 |
|
| Total Generation Consolidated Operating Revenues | $ | 12,903 |
| | $ | 1,377 |
| | $ | 14,280 |
| | $ | — |
| | $ | 14,280 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2018 |
| | Revenues from external customers(a) | | Intersegment
revenues | | Total
Revenues |
| | Contracts with customers | | Other(b) | | Total | | |
| Mid-Atlantic | $ | 3,971 |
| | $ | 191 |
| | $ | 4,162 |
| | $ | 17 |
| | $ | 4,179 |
|
| Midwest | 3,432 |
| | 169 |
| | 3,601 |
| | (8 | ) | | 3,593 |
|
| New York | 1,305 |
| | (37 | ) | | 1,268 |
| | 1 |
| | 1,269 |
|
| ERCOT | 470 |
| | 459 |
| | 929 |
| | 1 |
| | 930 |
|
| Other Power Regions | 2,656 |
| | 574 |
| | 3,230 |
| | (116 | ) | | 3,114 |
|
| Total Competitive Businesses Electric Revenues | 11,834 |
| | 1,356 |
| | 13,190 |
| | (105 | ) | | 13,085 |
|
| Competitive Businesses Natural Gas Revenues | 1,016 |
| | 823 |
| | 1,839 |
| | 105 |
| | 1,944 |
|
Competitive Businesses Other Revenues(c) | 385 |
| | (46 | ) | | 339 |
| | — |
| | 339 |
|
| Total Generation Consolidated Operating Revenues | $ | 13,235 |
| | $ | 2,133 |
| | $ | 15,368 |
| | $ | — |
| | $ | 15,368 |
|
__________
| |
(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 unrealized mark-to-market gains of $64 million and losses of $96 million in 2019 and 2018, respectively, and elimination of intersegment revenues. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Segment Information
Revenues net of purchased power and fuel expense (Generation):
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 | | Nine Months Ended September 30, 2018 |
| | RNF from external customers(a) | | Intersegment RNF | | Total RNF | | RNF from external customers(a) | | Intersegment RNF | | Total RNF |
| Mid-Atlantic | $ | 2,007 |
| | $ | 16 |
| | $ | 2,023 |
| | $ | 2,303 |
| | $ | 45 |
| | $ | 2,348 |
|
| Midwest | 2,269 |
| | (22 | ) | | 2,247 |
| | 2,381 |
| | 19 |
| | 2,400 |
|
| New York | 800 |
| | 10 |
| | 810 |
| | 832 |
| | 9 |
| | 841 |
|
| ERCOT | 252 |
| | (27 | ) | | 225 |
| | 396 |
| | (180 | ) | | 216 |
|
| Other Power Regions | 542 |
| | (64 | ) | | 478 |
| | 740 |
| | (133 | ) | | 607 |
|
| Total Revenues net of purchased power and fuel expense for Reportable Segments | 5,870 |
|
| (87 | ) |
| 5,783 |
|
| 6,652 |
|
| (240 | ) |
| 6,412 |
|
Other(b) | 262 |
| | 87 |
| | 349 |
| | 164 |
| | 240 |
| | 404 |
|
| Total Generation Revenues net of purchased power and fuel expense | $ | 6,132 |
|
| $ | — |
|
| $ | 6,132 |
|
| $ | 6,816 |
|
| $ | — |
|
| $ | 6,816 |
|
__________
| |
(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 unrealized mark-to-market losses of $84 million and $104 million in 2019 and 2018, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of $13 million and $53 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Segment Information
Electric and Gas Revenue by Customer Class (Utility Registrants):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2019 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 2,221 |
| | $ | 1,231 |
| | $ | 1,019 |
| | $ | 1,816 |
| | $ | 792 |
| | $ | 499 |
| | $ | 525 |
|
| Small commercial & industrial | 1,103 |
| | 304 |
| | 193 |
| | 387 |
| | 114 |
| | 141 |
| | 132 |
|
| Large commercial & industrial | 399 |
| | 163 |
| | 335 |
| | 843 |
| | 633 |
| | 75 |
| | 135 |
|
| Public authorities & electric railroads | 35 |
| | 23 |
| | 20 |
| | 47 |
| | 27 |
| | 10 |
| | 10 |
|
Other(a) | 660 |
| | 186 |
| | 242 |
| | 481 |
| | 166 |
| | 151 |
| | 164 |
|
Total rate-regulated electric revenues(b) | 4,418 |
| | 1,907 |
| | 1,809 |
| | 3,574 |
| | 1,732 |
| | 876 |
| | 966 |
|
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | — |
| | 285 |
| | 327 |
| | 64 |
| | — |
| | 64 |
| | — |
|
| Small commercial & industrial | — |
| | 122 |
| | 55 |
| | 30 |
| | — |
| | 30 |
| | — |
|
| Large commercial & industrial | — |
| | 1 |
| | 93 |
| | 4 |
| | — |
| | 4 |
| | — |
|
| Transportation | — |
| | 18 |
| | — |
| | 11 |
| | — |
| | 11 |
| | — |
|
Other(c) | — |
| | 5 |
| | 19 |
| | 6 |
| | — |
| | 6 |
| | — |
|
Total rate-regulated natural gas revenues(d) | — |
| | 431 |
| | 494 |
| | 115 |
| | — |
| | 115 |
| | — |
|
| Total rate-regulated revenues from contracts with customers | 4,418 |
| | 2,338 |
| | 2,303 |
| | 3,689 |
| | 1,732 |
| | 991 |
| | 966 |
|
| | | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | (98 | ) | | (16 | ) | | 11 |
| | 4 |
| | 10 |
| | (6 | ) | | — |
|
Other rate-regulated electric revenues(e) | 22 |
| | 10 |
| | 10 |
| | 7 |
| | 6 |
| | 1 |
| | — |
|
Other rate-regulated natural gas revenues(e) | — |
| | 1 |
| | 3 |
| | — |
| | — |
| | 1 |
| | — |
|
| Total other revenues | (76 | ) | | (5 | ) | | 24 |
| | 11 |
| | 16 |
| | (4 | ) | | — |
|
| Total rate-regulated revenues for reportable segments | $ | 4,342 |
| | $ | 2,333 |
| | $ | 2,327 |
| | $ | 3,700 |
| | $ | 1,748 |
| | $ | 987 |
| | $ | 966 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 18 — Segment Information
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2018 |
| Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Rate-regulated electric revenues | | | | | | | | | | | | | |
| Residential | $ | 2,277 |
| | $ | 1,199 |
| | $ | 1,054 |
| | $ | 1,839 |
| | $ | 792 |
| | $ | 513 |
| | $ | 534 |
|
| Small commercial & industrial | 1,132 |
| | 306 |
| | 196 |
| | 370 |
| | 104 |
| | 138 |
| | 128 |
|
| Large commercial & industrial | 411 |
| | 174 |
| | 325 |
| | 845 |
| | 632 |
| | 74 |
| | 139 |
|
| Public authorities & electric railroads | 36 |
| | 21 |
| | 21 |
| | 44 |
| | 24 |
| | 10 |
| | 10 |
|
Other(a) | 656 |
| | 181 |
| | 246 |
| | 446 |
| | 145 |
| | 129 |
| | 174 |
|
Total rate-regulated electric revenues(b) | 4,512 |
| | 1,881 |
| | 1,842 |
| | 3,544 |
| | 1,697 |
| | 864 |
| | 985 |
|
| Rate-regulated natural gas revenues | | | | | | | | | | | | | |
| Residential | — |
| | 259 |
| | 345 |
| | 68 |
| | — |
| | 68 |
| | — |
|
| Small commercial & industrial | — |
| | 102 |
| | 55 |
| | 31 |
| | — |
| | 31 |
| | — |
|
| Large commercial & industrial | — |
| | 1 |
| | 88 |
| | 7 |
| | — |
| | 7 |
| | — |
|
| Transportation | — |
| | 16 |
| | — |
| | 12 |
| | — |
| | 12 |
| | — |
|
Other(c) | — |
| | 4 |
| | 49 |
| | 11 |
| | — |
| | 11 |
| | — |
|
Total rate-regulated natural gas revenues(d) | — |
| | 382 |
| | 537 |
| | 129 |
| | — |
| | 129 |
| | — |
|
| Total rate-regulated revenues from contracts with customers | 4,512 |
| | 2,263 |
| | 2,379 |
| | 3,673 |
| | 1,697 |
| | 993 |
| | 985 |
|
| | | | | | | | | | | | | | |
| Other revenues | | | | | | | | | | | | | |
| Revenues from alternative revenue programs | (27 | ) | | 2 |
| | (23 | ) | | 7 |
| | 6 |
| | 5 |
| | (4 | ) |
Other rate-regulated electric revenues(e) | 23 |
| | 10 |
| | 10 |
| | 8 |
| | 5 |
| | 3 |
| | — |
|
Other rate-regulated natural gas revenues(e) | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
| | — |
|
| Total other revenues | (4 | ) | | 12 |
| | (10 | ) | | 15 |
| | 11 |
| | 8 |
| | (4 | ) |
| Total rate-regulated revenues for reportable segments | $ | 4,508 |
| | $ | 2,275 |
| | $ | 2,369 |
| | $ | 3,688 |
| | $ | 1,708 |
| | $ | 1,001 |
| | $ | 981 |
|
__________
| |
(a) | Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue. |
| |
(b) | Includes operating revenues from affiliates of $13 million, $4 million, $5 million, $11 million, $5 million, $5 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $23 million, $5 million, $5 million, $11 million $5 million, $6 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018. |
| |
(c) | Includes revenues from off-system natural gas sales. |
| |
(d) | Includes operating revenues from affiliates of less than $1 million and $13 million at PECO and BGE in 2019 and 2018, respectively. |
| |
(e) | Includes late payment charge revenues. |
| |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
(Dollars in millions except per share data, unless otherwise noted)
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���sGeneration’s five reportable segments (Mid-Atlantic, Midwest, 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 changed 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 disclosed five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. See Note 1 — Significant Accounting Policies and Note 184 — 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 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.
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. We have implemented work from home policies where appropriate, and imposed travel limitations on our 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 have been no changes in internal control over financial reporting to date 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 4. 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 2 – 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 recorded regulatory assets in the third quarter of 2020 for substantially all the incremental credit loss expense, including the expense recorded in the second quarter of 2020. See Note 2 – 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 2 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. The regulatory assets recorded at BGE, Pepco, DPL, and ACE in the third quarter of 2020 include expense recorded in the second quarter of 2020.
The estimated impact to Generation’s Net income is approximately $45 million and $140 million for the three and nine months ended September 30, 2020, respectively. The estimated impact to the Utility Registrants’ Net income is approximately $15 million and $65 million for the three and nine months ended September 30, 2020, respectively.
In the fourth quarter of 2020, Generation estimates a decrease in Net income due to net reduction in load of $15 million to $25 million. Generation load forecasts are highly dependent on many factors including, but not limited to, the duration of remaining restrictions and the speed and strength of the economic recovery.
To offset the unfavorable impacts from COVID-19, the Registrants identified and are pursuing approximately $250 million in cost savings across Generation and the Utility Registrants. The cost savings for the year are expected to be 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, to date in 2020, the Registrants have issued long-term debt of $5.3 billion and have now completed their planned long-term debt issuances for the 2020 year. See Liquidity and Capital Resources, Note 12 - Debt and Credit Agreements, and Note 5 - 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 to date in 2020 as a result of COVID-19. See Note 8 — 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 our workforce, our customers, and our suppliers and we will take additional precautions that we determine are 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 three and nine months ended September 30, 20192020 compared to the same period in 2018.2019. For additional information regarding the financial results for the three and nine months ended September 30, 20192020 and 20182019 see the discussions of Results of Operations by Registrant.
| | | | Three Months Ended September 30, | | Favorable (unfavorable) variance | | Nine Months Ended September 30, | | Favorable (unfavorable) variance | | Three Months Ended September 30, | | Favorable (unfavorable) variance | | Nine Months Ended September 30, | | Favorable (unfavorable) variance |
| | 2019 | | 2018 | | 2019 | | 2018 | | | 2020 | | 2019 | | 2020 | | 2019 | |
| Exelon | 772 |
| | 733 |
| | $ | 39 |
| | $ | 2,164 |
| | $ | 1,858 |
| | $ | 306 |
| Exelon | $ | 501 | | | $ | 772 | | | $ | (271) | | | $ | 1,604 | | | $ | 2,164 | | | $ | (560) | |
| Generation | 257 |
| | 234 |
| | 23 |
| | 728 |
| | 547 |
| | 181 |
| Generation | 49 | | | 257 | | | (208) | | | 570 | | | 728 | | | (158) | |
| ComEd | 200 |
| | 193 |
| | 7 |
| | 544 |
| | 523 |
| | 21 |
| ComEd | 196 | | | 200 | | | (4) | | | 304 | | | 544 | | | (240) | |
| PECO | 140 |
| | 126 |
| | 14 |
| | 410 |
| | 336 |
| | 74 |
| PECO | 138 | | | 140 | | | (2) | | | 317 | | | 410 | | | (93) | |
| BGE | 55 |
| | 63 |
| | (8 | ) | | 261 |
| | 242 |
| | 19 |
| BGE | 53 | | | 55 | | | (2) | | | 273 | | | 261 | | | 12 | |
| PHI | 189 |
| | 187 |
| | 2 |
| | 412 |
| | 336 |
| | 76 |
| PHI | 216 | | | 189 | | | 27 | | | 418 | | | 412 | | | 6 | |
| Pepco | 98 |
| | 89 |
| | 9 |
| | 217 |
| | 174 |
| | 43 |
| Pepco | 118 | | | 98 | | | 20 | | | 227 | | | 217 | | | 10 | |
| DPL | 33 |
| | 33 |
| | — |
| | 116 |
| | 90 |
| | 26 |
| DPL | 27 | | | 33 | | | (6) | | | 91 | | | 116 | | | (25) | |
| ACE | 63 |
| | 61 |
| | 2 |
| | 87 |
| | 76 |
| | 11 |
| ACE | 75 | | | 63 | | | 12 | | | 106 | | | 87 | | | 19 | |
Other(a) | (69 | ) | | (70 | ) | | 1 |
| | (191 | ) | | (126 | ) | | (65 | ) | Other(a) | (151) | | | (69) | | | (82) | | | (278) | | | (191) | | | (87) | |
__________
| |
(a) | 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.
Three Months Ended September 30, 20192020 Compared to Three Months Ended September 30, 2018.2019. Net income attributable to common shareholders increaseddecreased by $39$271 million and diluted earnings per average common share increaseddecreased to $0.51 in 2020 from $0.79 in 2019 from $0.76 in 2018 primarily due to:
Absence•Impairment of the New England asset group;
•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 the Oyster Creek nuclear facilityTMI in September 20182019;
•Reduction in load due to COVID-19 at Generation;
•COVID-19 direct costs; and
•Higher storm costs related to the August 2020 storm at PECO, net of tax repairs, and at DPL.
The decreases were partially offset by:
•Higher mark-to-market gains;
•Higher net unrealized gains on NDT funds;
•Lower operating and maintenance expense at Generation,primarily due to lower contracting and travel costs;
•Higher capacity revenue;
•Regulatory rate increases at BGE, DPL, and ACE; and
•Favorable weather conditions at PECO.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019.Net income attributable to common shareholders decreased by $560 million and diluted earnings per average common share decreased to $1.64 in 2020 from $2.22 in 2019 primarily due to:
•Impairment of the New England asset group;
•One-time chargesand 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 a charge associated withaccelerated depreciation and amortization due to the remeasurementearly retirement of TMI in September 2019;
•Payments that ComEd will make under the Deferred Prosecution Agreement. See Note 14 - Commitments and Contingencies of the Oyster Creek ARO;Combined Notes to Consolidated Financial Statements for additional information;
Decreased•Lower net unrealized and realized gains on NDT funds;
•Lower capacity revenue;
•Higher nuclear outage daysdays;
•Reduction in 2019;load due to COVID-19 at Generation;
Increased New York ZEC prices•COVID-19 direct costs;
•Lower allowed electric distribution ROE at ComEd due to a decrease in treasury rates;
•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;
•Lower operating and maintenance expense at Generation, primarily due to previous cost management programs, lower contracting costs, and lower travel costs;
•Lower nuclear fuel costs;
•The approval of the New Jersey ZEC program in the second quarter of 2019;
A benefit associated with the annual nuclear ARO update;•An income tax settlement at Generation; and
Decreased Operating and maintenance expense, which includes the impacts of previous cost management programs and lower pension and OPEB costs; and
•Regulatory rate increases at PECO, BGE, Pepco, DPL, and ACE.
The increases were partially offset by:
Lower capacity prices;
Lower mark-to-market gains;
Lower realized energy prices; and
Unfavorable weather conditions and volume at PECO.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Net income attributable to common shareholders increased by $306 million and diluted earnings per average common share increased to $2.22 in 2019 from $1.92 in 2018 primarily due to:
Higher net unrealized and realized gains on NDT funds;
Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018 and the absence of a charge associated with the remeasurement of the Oyster Creek ARO;
Decreased Operating and maintenance expense which includes the impacts of previous cost management programs and lower pension and OPEB costs;
Decreased nuclear outage days in 2019;
A benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019 and the annual nuclear ARO update in the third quarter of 2019;
Regulatory rate increases at PECO, BGE, Pepco, DPL, and ACE; and
Decreased storms costs at PECO and BGE.
The increases were partially offset by:
Lower realized energy prices;
Lower capacity prices;
The absence of the revenues recognized in the first quarter of 2018 related to ZECs generated in Illinois from June through December 2017, partially offset by increased New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 2019;
Higher mark-to-market losses; and
Unfavorable weather conditions and volume at PECO.
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 tables provide a reconciliation between net income attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 20192020 compared to the same period in 2018.2019.
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, |
| 2020 | | 2019 |
| (In millions, except per share data) | | | Earnings per
Diluted Share | | | | Earnings per
Diluted Share |
| Net Income Attributable to Common Shareholders | $ | 501 | | | $ | 0.51 | | | $ | 772 | | | $ | 0.79 | |
| Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $62 and $2, respectively) | (183) | | | (0.19) | | | (2) | | | — | |
Unrealized Gains Related to NDT Fund Investments (net of taxes of $161 and $34, respectively)(a) | (172) | | | (0.18) | | | (39) | | | (0.04) | |
Asset Impairments (net of taxes of $126 and $53, respectively)(b) | 375 | | | 0.38 | | | 113 | | | 0.12 | |
Plant Retirements and Divestitures (net of taxes of $111 and $40, respectively)(c) | 329 | | | 0.34 | | | 119 | | | 0.12 | |
Cost Management Program (net of taxes of $5 and $3, respectively)(d) | 15 | | | 0.02 | | | 14 | | | 0.01 | |
| Change in Environmental Liabilities (net of taxes of $6 and $5, respectively) | 17 | | | 0.02 | | | 18 | | | 0.02 | |
COVID-19 Direct Costs (net of taxes of $3)(e) | 10 | | | 0.01 | | | — | | | — | |
Asset Retirement Obligation (net of taxes of $1 and $9, respectively)(f) | 3 | | | — | | | (84) | | | (0.09) | |
Acquisition Related Costs (net of taxes of $1)(g) | 2 | | | — | | | — | | | — | |
Income Tax-Related Adjustments (entire amount represents tax expense)(h) | 62 | | | 0.06 | | | 13 | | | 0.01 | |
Noncontrolling Interests (net of taxes of $12 and $3, respectively)(i) | 57 | | | 0.06 | | | (24) | | | (0.02) | |
| Adjusted (non-GAAP) Operating Earnings | $ | 1,017 | | | $ | 1.04 | | | $ | 900 | | | $ | 0.92 | |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, |
| | 2019 | | 2018 |
| (All amounts in millions after tax) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share |
| Net Income Attributable to Common Shareholders | $ | 772 |
| | $ | 0.79 |
| | $ | 733 |
| | $ | 0.76 |
|
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $2 and $20, respectively) | (2 | ) | | — |
| | (55 | ) | | (0.06 | ) |
Unrealized Gains Related to NDT Fund Investments (net of taxes of $34 and $4, respectively)(a) | (39 | ) | | (0.04 | ) | | (53 | ) | | (0.06 | ) |
Asset Impairments (net of taxes of $53 and $2, respectively)(b) | 113 |
| | 0.12 |
| | 6 |
| | 0.01 |
|
Plant Retirements and Divestitures (net of taxes of $40 and $70, respectively)(c) | 119 |
| | 0.12 |
| | 202 |
| | 0.21 |
|
Cost Management Program (net of taxes of $3 and $4, respectively)(d) | 14 |
| | 0.01 |
| | 13 |
| | 0.01 |
|
Asset Retirement Obligation(e) (net of taxes of $9 and $6, respectively) | (84 | ) | | (0.09 | ) | | 16 |
| | 0.02 |
|
Change in Environmental Liabilities (net of taxes of $5 and $3, respectively) | 18 |
| | 0.02 |
| | (9 | ) | | (0.01 | ) |
Income Tax-Related Adjustments (entire amount represents tax expense)(f) | 13 |
| | 0.01 |
| | (18 | ) | | (0.02 | ) |
Noncontrolling Interests (net of taxes of $3 and $4, respectively)(g) | (24 | ) | | (0.02 | ) | | 21 |
| | 0.02 |
|
| Adjusted (non-GAAP) Operating Earnings | $ | 900 |
| | $ | 0.92 |
| | $ | 856 |
| | $ | 0.88 |
|
|
| | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, |
| | 2019 | | 2018 |
| (All amounts in millions after tax) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share |
| Net Income Attributable to Common Shareholders | $ | 2,164 |
| | $ | 2.22 |
| | $ | 1,858 |
| | $ | 1.92 |
|
| Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $31 and $26, respectively) | 97 |
| | 0.10 |
| | 74 |
| | 0.08 |
|
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $167 and $118, respectively)(a) | (181 | ) | | (0.19 | ) | | 94 |
| | 0.10 |
|
PHI Merger and Integration Costs (net of taxes of $1) | — |
| | — |
| | 5 |
| | — |
|
Asset Impairments (net of taxes of $54 and $13, respectively)(b) | 119 |
| | 0.12 |
| | 36 |
| | 0.04 |
|
Plant Retirements and Divestitures (net of taxes of $9 and $148, respectively)(c) | 114 |
| | 0.12 |
| | 422 |
| | 0.43 |
|
Cost Management Program (net of taxes of $10 and $10, respectively)(d) | 31 |
| | 0.03 |
| | 29 |
| | 0.03 |
|
| Litigation Settlement Gain (net of taxes of $7) | (19 | ) | | (0.02 | ) | | — |
| | — |
|
Asset Retirement Obligation (net of taxes of $9 and $6, respectively)(e) | (84 | ) | | (0.09 | ) | | 16 |
| | 0.02 |
|
Change in Environmental Liabilities (net of taxes of $5 and $1, respectively) | 18 |
| | 0.02 |
| | (4 | ) | | — |
|
Income Tax-Related Adjustments (entire amount represents tax expense)(f) | 13 |
| | 0.01 |
| | (27 | ) | | (0.03 | ) |
Noncontrolling Interests (net of taxes of $18 and $9, respectively)(g) | 58 |
| | 0.06 |
| | (36 | ) | | (0.04 | ) |
| Adjusted (non-GAAP) Operating Earnings | $ | 2,329 |
| | $ | 2.39 |
| | $ | 2,467 |
| | $ | 2.55 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2020 | | 2019 |
| (In millions, except per share data) | | | Earnings per
Diluted Share | | | | Earnings per
Diluted Share |
| Net Income Attributable to Common Shareholders | $ | 1,604 | | | $ | 1.64 | | | $ | 2,164 | | | $ | 2.22 | |
| Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $112 and $31, respectively) | (329) | | | (0.34) | | | 97 | | | 0.10 | |
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $31 and $167, respectively)(a) | 8 | | | 0.01 | | | (181) | | | (0.19) | |
Asset Impairments (net of taxes of $134 and $54, respectively)(b) | 396 | | | 0.40 | | | 119 | | | 0.12 | |
Plant Retirements and Divestitures (net of taxes of $117 and $9, respectively)(c) | 348 | | | 0.36 | | | 114 | | | 0.12 | |
Cost Management Program (net of taxes of $11 and $10, respectively)(d) | 34 | | | 0.03 | | | 31 | | | 0.03 | |
| Litigation Settlement Gain (net of taxes of $7) | — | | | — | | | (19) | | | (0.02) | |
| Change in Environmental Liabilities (net of taxes of $6 and $5, respectively) | 18 | | | 0.02 | | | 18 | | | 0.02 | |
COVID-19 Direct Costs (net of taxes of $13)(e) | 37 | | | 0.04 | | | — | | | — | |
Deferred Prosecution Agreement Payments (net of taxes of $0)(j) | 200 | | | 0.20 | | | — | | | — | |
Asset Retirement Obligation (net of taxes of $1 and $9, respectively)(f) | 3 | | | — | | | (84) | | | (0.09) | |
Acquisition Related Costs (net of tax of $1)(g) | 2 | | | — | | | — | | | — | |
Income Tax-Related Adjustments (entire amount represents tax expense)(h) | 66 | | | 0.07 | | | 13 | | | 0.01 | |
Noncontrolling Interests (net of taxes of $2 and $18, respectively)(i) | 17 | | | 0.02 | | | 58 | | | 0.06 | |
| Adjusted (non-GAAP) Operating Earnings | $ | 2,403 | | | $ | 2.46 | | | $ | 2,329 | | | $ | 2.39 | |
__________
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 fund investments, the marginal statutory income tax rates for 20192020 and 20182019 ranged from 26.0 percent26.0% to 29.0 percent.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 fund investments were 47.1 percent48.3% and 7.7 percent47.1% for the three months ended September 30, 20192020 and 2018,2019, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 48.1 percent134.1% and 55.5 percent48.1% for the nine months ended September 30, 20192020 and 2018,2019, 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 2018, primarily reflects the impairment of certain wind projects at Generation. In 2019, primarily reflects the impairment of equity method investments in certain distributed energy companies. |
| |
(c) | In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek and TMI nuclear facilities, a charge associated with a remeasurement of the Oyster Creek ARO, partially offset by a gain associated with Generation's sale of its electrical contracting business. 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 costs related to cost management programs. |
| |
(e) | In 2018, reflects an increase at Pepco related primarily to asbestos identified at its Buzzard Point property. In 2019, reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units.
|
| |
(f) | In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA. In 2019, primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment. |
| |
(g) | Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items. In 2018, primarily related to the impact of unrealized losses on NDT fund investments for CENG units. In 2019, primarily related to |
(a)Reflects the impact of net unrealized gains 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, primarily reflects an impairment in the New England asset group. 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 chargesand 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, a charge associated with a remeasurement of the TMI ARO and the loss on sale of Oyster Creek to Holtec.
(d)Primarily represents reorganization and severance costs related to cost management programs.
(e)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.
(f)In 2019, reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units.
(g)Reflects costs related to the acquisition of EDF's interest in CENG.
(h)Primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.
(i)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 the impairment of equity investments in distributed energy companies, partially offset by the impact of Generation's annual nuclear ARO update and unrealized gains on NDT fund investments for CENG units.
(j)Reflects the payments that ComEd will make under the Deferred Prosecution Agreement. See Note 14 - Commitments and the impactContingencies of the Generation's annual nuclear ARO updateCombined Notes to Consolidated Financial Statements for CENG units, partially offset by the impairment of certain equity investments in distributed energy companies.additional information.
Significant 20192020 Transactions and Developments
Cost Management ProgramsEarly 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 continuesand 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 in the third quarter of 2020 and the estimated amounts of incremental expense expected to be committedincurred for full year 2020 and through the retirement dates.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Projected(a) |
| Income statement expense (pre-tax) | Three and Nine Months Ended September 30, 2020 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 |
| Depreciation and amortization | | | | | | | | | | | |
Accelerated depreciation(b) | $ | 260 | | | $ | 930 | | | $ | 2,110 | | | $ | 105 | | | $ | 115 | | | $ | 50 | |
| Accelerated nuclear fuel amortization | 14 | | | 60 | | | 180 | | | — | | | — | | | — | |
| Operating and maintenance | | | | | | | | | | | |
| One-time charges | 263 | | | 265 | | | 20 | | | — | | | — | | | — | |
Other charges(c) | 34 | | | 40 | | | 5 | | | 5 | | | 5 | | | — | |
| | | | | | | | | | | |
Contractual offset(d) | (129) | | | (370) | | | (755) | | | — | | | — | | | — | |
| Total | $ | 442 | | | $ | 925 | | | $ | 1,560 | | | $ | 110 | | | $ | 120 | | | $ | 50 | |
| | | | | | | | | | | |
_________
(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 7 – Nuclear Decommissioning of the Combined Notes to managing its costs. On October 31, 2019, Exelon announcedConsolidated Financial Statements for additional annual cost savingsinformation.
(d)Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of approximately $100 million,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. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation to be achieved by 2022. These actions are in responseand an adjustment to the continuing economic challenges confronting Generation’s business, necessitating continued focus on cost management through enhanced efficiency and productivity.regulatory liabilities at ComEd. See Note 9 – Asset Retirement Obligations of the Exelon 2019 Form 10-K for additional information.
Conowingo Hydroelectric Project
In connection with Generation’s pursuit of a new FERC license for Conowingo, on October 29, 2019, Generation and MDEDeferred Prosecution Agreement
On July 17, 2020, ComEd entered into a settlement agreementDeferred 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 would resolve all outstanding issues betweenComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the parties, effective uponbenefit 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 FERC’s approval and incorporationcertain obligations of ComEd, including payment to the United States Treasury of $200 million, with $100 million payable within thirty days of the terms into the new license when issued. The financial impact of this settlement, along with other anticipated and prior license commitments, would be recognized over the termfiling of the new 50-year licenseDPA with the United States District Court for the Northern District of Illinois and is estimatedan additional $100 million within ninety days of such filing date. The payments will not be recovered in rates or charged to be, on average, $11 million to $14 million per year, including capitalcustomers, and operating costs. The actual timingComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. See Note 14 — Commitments and amount of a 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.Contingencies for additional information.
Utility Rates and Base Rate 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 2019.2020. See Note 62 — 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 | Requested Revenue Requirement (Decrease) Increase | Approved Revenue Requirement (Decrease) Increase | Approved ROE | Approval Date | Rate Effective Date |
| | | | | | |
| | | | | | |
| | | | | | |
| ComEd - Illinois (Electric) | April 8, 2019 | $ | (6) | | $ | (17) | | 8.91 | % | December 4, 2019 | January 1, 2020 |
| DPL - Maryland (Electric) | December 5, 2019 (amended April 23, 2020) | 17 | | 12 | | 9.60 | % | July 14, 2020 | July 16, 2020 |
| | | | | | |
|
| | | | | | | | | | | |
| Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement (Decrease) Increase | Approved Revenue Requirement (Decrease) Increase | Approved ROE | Approval Date | Rate Effective Date |
| ComEd - Illinois (Electric) | April 16, 2018 | $ | (23 | ) | $ | (24 | ) | 8.69 | % | December 4, 2018 | January 1, 2019 |
| PECO - Pennsylvania (Electric) | March 29, 2018 | $ | 82 |
| $ | 25 |
| N/A |
| December 20, 2018 | January 1, 2019 |
| BGE - Maryland (Natural Gas) | June 8, 2018 (amended October 12, 2018) | $ | 61 |
| $ | 43 |
| 9.8 | % | January 4, 2019 | January 4, 2019 |
| ACE - New Jersey (Electric) | August 21, 2018 (amended November 19, 2018) | $ | 122 |
| $ | 70 |
| 9.6 | % | March 13, 2019 | April 1, 2019 |
| Pepco - Maryland (Electric) | January 15, 2019 (amended May 16, 2019) | $ | 27 |
| $ | 10 |
| 9.6 | % | August 12, 2019 | August 13, 2019 |
Pending Distribution Base Rate Case Proceedings
| | | | | | | | | | | | | | |
| Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement (Decrease) Increase | Requested ROE | Expected Approval Timing |
| ComEd - Illinois (Electric) | April 16, 2020 | $ | (11) | | 8.38 | % | Fourth quarter of 2020 |
| PECO - Pennsylvania (Natural Gas) | September 30, 2020 | 69 | | 10.95 | % | Second quarter of 2021 |
| BGE - Maryland (Electric and Natural Gas) | May 15, 2020
(amended September 11, 2020) | 228 | | 10.1 | % | Fourth quarter of 2020 |
| Pepco - District of Columbia (Electric) | May 30, 2019 (amended June 1, 2020) | 136 | | 9.7 | % | First quarter of 2021 |
| Pepco - Maryland (Electric) | October 26, 2020 | 110 | | 10.2 | % | Second quarter of 2021 |
| DPL - Delaware (Natural Gas) | February 21, 2020 (amended October 9, 2020) | 7 | | 10.3 | % | First quarter of 2021 |
| DPL - Delaware (Electric) | March 6, 2020 (amended October 26, 2020) | 24 | | 10.3 | % | Second quarter of 2021 |
|
| | | | | | | |
| Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement (Decrease) Increase | Requested ROE | Expected Approval Timing |
| ComEd - Illinois (Electric) | April 8, 2019 | $ | (6 | ) | 8.91 | % | December 2019 |
BGE - Maryland (Electric)(a) | May 24, 2019 (amended October 4, 2019) | $ | 74 |
| 10.3 | % | December 2019 |
BGE - Maryland (Natural Gas)(a) | May 24, 2019 (amended October 4, 2019) | $ | 59 |
| 10.3 | % | December 2019 |
| Pepco - District of Columbia (Electric) | May 30, 2019 (amended September 16, 2019) | $ | 160 |
| 10.3 | % | Fourth quarter of 2020 |
__________
| |
(a) | On October 25, 2019, BGE filed a settlement agreement with the MDPSC. The settlement provides for an increase to BGE’s annual electric and natural gas distribution rates of $18 million and $45 million, respectively.
|
Transmission Formula RateRates
Transmission Formula Rate (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE). ComEd’s, PECO'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-approved formula on or before May 15 and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same 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 revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The update for PECO and Pepco also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2020, the following total increases/(decreases) were included in ComEd's, BGE's,ComEd’s, PECO's, BGE’s, Pepco's, DPL's, and ACE's 2019 annual electric transmission formula rate updates.filings:
| | | | | | | | | | | | | | | | | |
| 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 | % |
|
| | | | | | | | | | |
| Registrant | Initial Revenue Requirement Increase (Decrease) | Annual Reconciliation Increase (Decrease) | Total Revenue Requirement Increase (Decrease) | Allowed Return on Rate Base | Allowed ROE |
| ComEd | 21 |
| (16 | ) | 5 |
| 8.21 | % | 11.50 | % |
| BGE | (10 | ) | (23 | ) | (19 | ) | 7.35 | % | 10.50 | % |
| Pepco | 15 |
| 11 |
| 26 |
| 7.75 | % | 10.50 | % |
| DPL | 17 |
| (1 | ) | 16 |
| 7.14 | % | 10.50 | % |
| ACE | 11 |
| (2 | ) | 9 |
| 7.79 | % | 10.50 | % |
PECO Transmission Formula RateSales of Customer Accounts Receivable
On May 1, 2017, PECO filedApril 8, 2020, NER, a request with FERC seeking approval to update its transmission rates and change the manner inbankruptcy remote, special purpose entity, 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. PECO’s initial formula rate filing included a requested increase of $22 million to PECO’s annual transmission revenue requirement, which reflected a ROE of 11%, inclusive of a 50 basis point adder for being a member of a RTO. 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.
Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were effective on June 1, 2018 and 2019, respectively, subject to refund.
On July 22, 2019, PECO and other parties filed with FERC a settlement agreement, which includes a ROE of 10.35%, inclusive of a 50 basis point adder for being a member of a RTO. The settlement did not have a material impact on PECO’s 2017, 2018, or 2019 annual transmission revenue requirements. A final order from FERC is expected before the end of the first quarter of 2020. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.
Early Plant Retirements and Divestitures
Oyster Creek. Generation permanently ceased generation operations at Oyster Creek on September 17, 2018. On July 31, 2018,wholly owned by Generation, entered into an agreementaccounts receivable financing facility with Holtec Internationala number of financial institutions and its wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, fora commercial paper conduit to sell certain customer accounts receivables. Generation received approximately $500 million of cash in accordance with the initial sale and decommissioning of Oyster Creek. The sale was completed on July 1, 2019. Exelon and Generation recognized a loss on the sale in the third quarter 2019, which was immaterial.approximately $1.2 billion receivables. See Note 35 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Three Mile Island. Generation permanently ceased operations at TMI on September 20, 2019. As a result of the decision to early retire TMI, Exelon and Generation recorded a $113 million and $185 million incremental pre-tax net charge for the three and nine months ended September 30, 2019 primarily due to accelerated depreciation of the plant assets, partially offset by a benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019.
Salem. In 2017, PSEG announced that its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest, were showing increased signs of economic distress, which could lead to an early retirement. PSEG is the operator of Salem and also has the decision-making authority to retire Salem. In 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. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Assuming the continued effectiveness of the New Jersey ZEC program, Generation no longer considers Salem to be at heightened risk for early retirement.
Dresden, Byron and Braidwood. 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. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.
See Note 6 — Regulatory Matters, Note 8 — Early Plant Retirements and Note 13 — Nuclear DecommissioningAccounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
Pacific Gas & Electric Bankruptcy
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, 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. As of September 30, 2019, Generation had approximately $730 million and $495 million of net long-lived assets and nonrecourse debt outstanding, respectively, related to Antelope Valley. PG&E’s bankruptcy created an event of default for Antelope Valley’s nonrecourse debt that provides 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 ongoing event of default and 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 and continues to be classified as current as of September 30, 2019.
In the first quarter of 2019, Generation assessed and determined that Antelope Valley’s long-lived assets were not impaired. Significant 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's net long-lived assets, which could be material. 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.
See Note 7 — Asset Impairments and Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the PG&E bankruptcy.
Other Key Business Drivers and Management Strategies
The following discussion of other key business driver and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -— Other Key Business Drivers and Management Strategies in the Registrants' combined 20182019 Form 10-K and Note 16 -14 — Commitments and Contingencies to the Consolidated Financial Statements in this report for additional information on various environmental matters.
Power Markets
Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs
PJM and NYISO capacity markets include a 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 Jersey ZEC, 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 and are no different than other renewable support 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, an expanded MOPR could 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, which could have a material effect on Exelon’s and Generation’s future cash flows and results of operations.
In June 2018, FERC addressed one of the MOPR complaints involving PJM and concluded 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. FERC suggested that modifying two elements of PJM’s existing tariff, as follows could produce a just and reasonable replacement.
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.
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 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. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. On April 10, 2019, PJM notified FERC of its intent to proceed with the next capacity auction in August 2019 under the existing market rules and asked FERC to clarify that it would not require PJM to re-run the auction in the event FERC alters those market rules in its decision on the MOPR complaint. On July 25, 2019, FERC issued an order denying PJM’s request to clarify that any alteration of PJM’s existing market rules would operate prospectively and, therefore, directed PJM to not conduct the capacity auction in August 2019. 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.
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.
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)("DOC") seeking relief under Section 232 of the Trade Expansion Act of 1962 as amended, (the Act) from imports of uranium products, alleging that these imports threaten national security (the Petition). The relief requested would have required U.S. nuclear reactors to purchase at least 25% of their uranium needs from domestic mines for the next 10 years or more. The Act was promulgated by Congress to protect essential national security industries whose survival is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.security.
On July 18, 2018, the Secretary announced that the DOC had initiated an investigation in response to the petition. The Secretary submitted a report to President Trump on April 14, 2019 that has not been made public. On July 12, 2019, the President issued a memorandum indicating that he did not agree with the Secretary’s finding that uranium imports threaten to impair the national security of the United States, choosing not to impose any trade restrictions at this time. The President found that a fuller analysis of national security considerations with respect to the entire nuclear fuel supply chain is necessary and directed that a United States Nuclear Fuel Working Group (Working Group) be established to develop recommendations for reviving and expanding domestic nuclear fuel production with a mandate to submit a("Working Group") report back to him within 90 days. On October 10, 2019, the President granted a 30-day extension to the deadline for the Working Group to submit the 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 co-chairedextended 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 the Assistant to the President for National Security Affairsexecutive agencies, congress, and the Assistant to the President for Economic Policy. Exelon will monitor and volunteer to provide information to support the Working Group’s efforts.or regulatory bodies. Exelon and Generation cannot currently predict the outcome of all of the policy changes recommended by the Working Group report and subsequent actions.Group.
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 September 30, 2019,2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 96%-99%, 84%-87%97%-100% and 54%-57%87%-90% for 2019, 2020 and 2021, respectively. 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 63%60% of Generation’s uranium concentrate requirements from 20192020 through 20232024 are supplied by three producers.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 results of operations, cash flows and financial statements.
positions.
See Note 1011 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and Item 3. 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.
Environmental Legislative and Regulatory Developments
Air Quality
Clean Power Plan. Mercury and Air Toxics Standards Rule (MATS).On December 16, 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 April 28, 2017,2014, the U.S. Court of Appeals for the D.C. Circuit issued a decision upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate power plant emissions of hazardous air pollutants, but did not vacate MATS. In 2016, the EPA issued a supplemental finding responding to the U.S. Supreme Court’s decision; the EPA concluded that, after considering costs, it remained appropriate and necessary to regulate hazardous air pollutants from power plants. On May 22, 2020, however, 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 D.C. Circuit Court seeking vacatur of MATS based on EPA’s May 22, 2020 ruling. On September 11, 2020, the court granted a motion by Exelon and two other entities to intervene in that lawsuit to defend MATS, and on September 28, 2020, the court issued ordersan order holding this portion of MATS litigation in separate litigation related toabeyance. On July 21, 2020, Exelon and two other entities filed a lawsuit in the D.C. Circuit Court challenging the EPA’s actions underMay 22, 2020 rescission of the appropriate and necessary finding underpinning MATS; litigation on this portion of the case is ongoing.
The Clean Power Plan and Affordable Clean Energy Rule. The EPA’s 2015 Clean Power Plan (CPP) to amendestablished regulations addressing carbon dioxide emissions from existing fossil-fired power plants under Clean Air Act Section 111(d) regulation of existing fossil-fired. The CPP’s carbon pollution limits could be met through changes to the electric generatinggeneration system, including shifting generation from higher-emitting units and Section 111(b) regulationto lower- or zero-emitting units, as well as the development of new fossil-fired electric generating units.or expanded zero-emissions generation. In both cases,July 2019, the Court has determined to hold the litigation in abeyance pending a determination whether theEPA published its final Affordable Clean Energy rule, should be remanded to the EPA. In June 2019, EPA issued a final rule thatwhich repealed the CPP and finalized the Affordable Clean Energy rule to replace the CPPreplaced it with less stringent emissions guidelines for existing coal-fired power plants based on heat rate improvement measures that could be achieved within the fence line of existing powerindividual plants.
Primary SO2 National Ambient Air Quality Standards (NAAQS). EPA took final action 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 April 17,September 6, 2019, to retainchallenging the current primary SO2 standard without revision, leaving the standard established in 2010 in effect.
See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to environmental matters, including the impact of environmental regulation.
Other Legislative and Regulatory Developments
IllinoisAffordable Clean Energy Progress Act
On March 14, 2019,rule as unlawful. This lawsuit has been consolidated with separate challenges to the Affordable Clean Energy Progress Act was introduced in the Illinois General Assembly to preserve Illinois’ clean energy choices arising from FEJArule filed by various states, non-governmental organizations, and empower the IPA to conduct capacity procurements outside of PJM’s base residual auction process, while utilizing the fixed resource requirement 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 clean energy resources, (2) it establishes a goal of achieving 100% carbon-free power in the ComEd service territory by 2032, and (3) it implements reforms to enhance consumer protections in the state’s competitive retail electricity and natural gas markets, including Generation’s retail customers. Energy legislation has also been proposed by other stakeholders, including renewable resource developers, environmental advocates, and coal-fueled generators. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.
Keep Powering Pennsylvania Act
On March 11, 2019, the Keep Powering Pennsylvania Act was introduced in the Pennsylvania General Assembly to amend the Alternative Energy Portfolio Standards Act of 2004. The proposed legislation recognizes the value that all zero-emission electric generation resources provide to Pennsylvania by adding nuclear plants and certain other renewable generation resources (Tier III resources) to the zero-emission electric generation resources that currently receive alternative energy credits in Pennsylvania. Further, the proposed legislation would allow for these Tier III resources to continue to receive capacity payments at the same level as the PJM capacity auction clearing price. In order to initially qualify as a Tier III resource, a resource must make a commitment to operate for at least six years. The price of the alternative energy credits for Tier III resources is tied to the value of existing Tier I resources, with a price cap. Regulated utilities, including PECO, would be required to purchase alternative energy credits for all retail customers and allowed to recover those costs from customers. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.
Nuclear Powers Act of 2019
On April 12, 2019, the Nuclear Powers America Act of 2019 was introduced to the United States Congress, which expands the current 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 credit rate would be reduced to 26% in 2024, 22% in 2025, and 10% in 2026 and beyond. To qualify for the credit, the plant must be currently operational and must have applied for an operating license renewal before 2026. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.business coalitions.
Employees
In April 2019, the second quarter of 2020, Generation, ComEd, and DPL ratified or extended CBAs as follows:
•Generation ratified its CBA with SPFPA Local 238, which covers 122 security officers at Quad Cities. The CBA expires in 2023.
•ComEd extended its CBA with IBEW Local 15 coveringto 2022, which covers 80 employees in the System Services Group.
•DPL ratified its CBAs with IBEW Locals 1238 and 1307, which together cover 857 employees. Both CBAs expire in 2024.
In the third quarter of 2020, Generation ratified CBAs as follows:
•CBA with SEIU Local 1, which covers 102 security officers at BSC, ComEd and Generation, were extended through 2024. In June 2019, BGE’s union contract for approximately 1,400 employees within Local 410 was ratified, which did not have a material impact on BGE's financial statements. In July 2019, theLaSalle. The CBA between Generation and the Security Officer’s union at Byron, which was scheduled to expire on September 30, 2019, was extended to December 31, 2019. In September 2019, negotiations completed between Pepco andexpires in 2023.
•CBA with IBEW Local 1900 and the CBA will expire in 2022. In September 2019, the CBA between Generation and Local 614, which covers 74 employees at Conowingo, Eddystone, and Fairless Hills stations,Fairless. The CBA expires in 2023.
In the fourth quarter of 2020, Generation ratified CBAs as follows:
•CBA with UGSOA Local 12, which was scheduled to expire on November 3, 2019, was extended to March 3, 2020.covers 113 security officers at Limerick. The CBA expires in 2025.
•CBA with IBEW Local 97, which covers 494 employees at Nine Mile Point. The CBA expires in 2025. Critical Accounting Policies and Estimates
Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. At September 30, 2019,2020, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2018.2019. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the Registrants' 20182019 Form 10-K for further information.
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.
Results of Operations — Generation
| | | | Three Months Ended
September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended
September 30, | | Favorable (Unfavorable) Variance | | Three Months Ended
September 30, | | Favorable
(Unfavorable)
Variance | | Nine Months Ended
September 30, | |
Favorable
(Unfavorable)
Variance |
| | 2019 | | 2018 | | 2019 | | 2018 | | | 2020 | | 2019 | | 2020 | | 2019 | |
| Operating revenues | $ | 4,774 |
| | $ | 5,278 |
| | $ | (504 | ) | | $ | 14,280 |
| | $ | 15,368 |
| | $ | (1,088 | ) | Operating revenues | $ | 4,659 | | | $ | 4,774 | | | $ | (115) | | | $ | 13,272 | | | $ | 14,280 | | | $ | (1,008) | |
| Purchased power and fuel expense | 2,651 |
| | 2,980 |
| | 329 |
| | 8,148 |
| | 8,552 |
| | 404 |
| Purchased power and fuel expense | 2,314 | | | 2,651 | | | 337 | | | 6,961 | | | 8,148 | | | 1,187 | |
| Revenues net of purchased power and fuel expense | 2,123 |
| | 2,298 |
| | (175 | ) | | 6,132 |
| | 6,816 |
| | (684 | ) | Revenues net of purchased power and fuel expense | 2,345 | | | 2,123 | | | 222 | | | 6,311 | | | 6,132 | | | 179 | |
| Other operating expenses | | | | | | | | | | | | Other operating expenses | |
| Operating and maintenance | 1,087 |
| | 1,370 |
| | 283 |
| | 3,570 |
| | 4,126 |
| | 556 |
| Operating and maintenance | 1,737 | | | 1,087 | | | (650) | | | 4,188 | | | 3,570 | | | (618) | |
| Depreciation and amortization | 407 |
| | 468 |
| | 61 |
| | 1,221 |
| | 1,383 |
| | 162 |
| Depreciation and amortization | 558 | | | 407 | | | (151) | | | 1,161 | | | 1,221 | | | 60 | |
| Taxes other than income | 129 |
| | 143 |
| | 14 |
| | 394 |
| | 414 |
| | 20 |
| |
| Taxes other than income taxes | | Taxes other than income taxes | 118 | | | 129 | | | 11 | | | 364 | | | 394 | | | 30 | |
| Total other operating expenses | 1,623 |
| | 1,981 |
| | 358 |
| | 5,185 |
| | 5,923 |
| | 738 |
| Total other operating expenses | 2,413 | | | 1,623 | | | (790) | | | 5,713 | | | 5,185 | | | (528) | |
| (Loss) gain on sales of assets and businesses | (18 | ) | | (6 | ) | | (12 | ) | | 15 |
| | 48 |
| | (33 | ) | |
| Operating income | 482 |
|
| 311 |
| | 171 |
| | 962 |
|
| 941 |
| | 21 |
| |
| | (Loss) Gain on sales of assets and businesses | | (Loss) Gain on sales of assets and businesses | — | | | (18) | | | 18 | | | 12 | | | 15 | | | (3) | |
| | Operating (loss) income | | Operating (loss) income | (68) | | | 482 | | | (550) | | | 610 | | | 962 | | | (352) | |
| Other income and (deductions) | | | | | | | | | | | | Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | (109 | ) | | (101 | ) | | (8 | ) | | (336 | ) | | (305 | ) | | (31 | ) | Interest expense, net | (80) | | | (109) | | | 29 | | | (277) | | | (336) | | | 59 | |
| Other, net | 128 |
| | 179 |
| | (51 | ) | | 729 |
| | 164 |
| | 565 |
| Other, net | 367 | | | 128 | | | 239 | | | 199 | | | 729 | | | (530) | |
| Total other income and (deductions) | 19 |
| | 78 |
| | (59 | ) | | 393 |
| | (141 | ) | | 534 |
| Total other income and (deductions) | 287 | | | 19 | | | 268 | | | (78) | | | 393 | | | (471) | |
| Income before income taxes | 501 |
| | 389 |
| | 112 |
| | 1,355 |
| | 800 |
| | 555 |
| Income before income taxes | 219 | | | 501 | | | (282) | | | 532 | | | 1,355 | | | (823) | |
| Income taxes | 87 |
| | 78 |
| | (9 | ) | | 388 |
| | 110 |
| | (278 | ) | Income taxes | 100 | | | 87 | | | (13) | | | 41 | | | 388 | | | 347 | |
| Equity in losses of unconsolidated affiliates | (170 | ) | | (11 | ) | | (159 | ) | | (183 | ) | | (23 | ) | | (160 | ) | Equity in losses of unconsolidated affiliates | (2) | | | (170) | | | 168 | | | (6) | | | (183) | | | 177 | |
| Net income | 244 |
|
| 300 |
|
| (56 | ) |
| 784 |
|
| 667 |
|
| 117 |
| Net income | 117 | | | 244 | | | (127) | | | 485 | | | 784 | | | (299) | |
| Net (loss) income attributable to noncontrolling interests | (13 | ) | | 66 |
| | 79 |
| | 56 |
| | 120 |
| | 64 |
| |
| Net income (loss) attributable to noncontrolling interests | | Net income (loss) attributable to noncontrolling interests | 68 | | | (13) | | | 81 | | | (85) | | | 56 | | | (141) | |
| Net income attributable to membership interest | $ | 257 |
| | $ | 234 |
| | $ | 23 |
| | $ | 728 |
| | $ | 547 |
| | $ | 181 |
| Net income attributable to membership interest | $ | 49 | | | $ | 257 | | | $ | (208) | | | $ | 570 | | | $ | 728 | | | $ | (158) | |
Three Months Ended September 30, 20192020 Compared to Three Months Ended September 30, 2018.2019. Net income attributable to membership interest increaseddecreased $208 million by $23 million primarilyprimarily due to:
Absence•Impairment of the New England asset group;
•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;
•Reduction in load due to COVID-19; and
•COVID-19 direct costs.
The decreases were partially offset by:
•Higher mark-to-market gains;
•Higher net unrealized gains on NDT funds;
•Lower operating and maintenance expense primarily due to lower contracting and travel costs; and
•Higher capacity revenue.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019.Net income attributable to membership interest decreased $158 million by primarily due to:
•Impairment of the New England asset group;
•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 the Oyster Creek nuclear facilityTMI in September 20182019;
•Lower net unrealized and the absence of a charge associated with the remeasurement of the Oyster Creek ARO;realized gains on NDT funds;
Decreased•Lower capacity revenue;
•Higher nuclear outage daysdays;
•Reduction in 2019;load due to COVID-19; and
Increased New York ZEC prices•COVID-19 direct costs.
The decreases were partially offset by:
•Higher mark-to-market gains;
•Lower operating and maintenance expense primarily due to previous cost management programs, lower contracting costs, and lower travel costs;
•Lower depreciation and amortization expense due to the impact of extending the operating license at Peach Bottom;
•Lower nuclear fuel costs;
•The approval of the New Jersey ZEC program in the second quarter of 2019;
A benefit associated with the annual nuclear ARO update; and
Decreased Operating and maintenance expense, which includes the impacts of previous cost management programs and lower pension and OPEB costs.
The increases were partially offset by:
Lower capacity prices;
Lower mark-to-market gains; and
Lower realized energy prices.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.•NetAn income attributable to membership interesttax settlement. increased by $181 million primarily due to:
Higher net unrealized and realized gains on NDT funds;
Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018 and the absence of a charge associated with the remeasurement of the Oyster Creek ARO;
Decreased Operating and maintenance expense which includes the impacts of previous cost management programs and lower pension and OPEB costs;
Decreased nuclear outage days in 2019; and
A benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019 and the annual nuclear ARO update in the third quarter of 2019.
The increases were partially offset by:
Lower realized energy prices;
Lower capacity prices;
The absence of the revenues recognized in the first quarter of 2018 related to ZECs generated in Illinois from June through December 2017, partially offset by increased New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 2019; and
Higher mark-to-market losses.
Revenues Net of Purchased Power and Fuel Expense. 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 with these same geographic regions. Generation's five reportable segments are Mid-Atlantic,Mid-
Atlantic, Midwest, New 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. See Note 244 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information.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: 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 three and nine months ended September 30, 2020 compared to 2019, and 2018, RNF by region were as follows:follows. See Note 4 - 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.
| | | | Three Months Ended
September 30, | | Variance | | % Change | | Nine Months Ended
September 30, | | Variance | | % Change | | Three Months Ended
September 30, | | Variance | | % Change | | Nine Months Ended
September 30, | | Variance | | % Change |
| | 2019 | | 2018 | | 2019 | | 2018 | | | 2020 | | 2019 | | 2020 | | 2019 | |
Mid-Atlantic(a) | $ | 689 |
| | $ | 763 |
| | $ | (74 | ) | | (9.7 | )% | | $ | 2,023 |
| | $ | 2,348 |
| | $ | (325 | ) | | (13.8 | )% | Mid-Atlantic(a) | $ | 591 | | | $ | 689 | | | $ | (98) | | | (14.2) | % | | $ | 1,683 | | | $ | 2,023 | | | $ | (340) | | | (16.8) | % |
Midwest(b) | 747 |
| | 768 |
| | (21 | ) | | (2.7 | )% | | 2,247 |
| | 2,400 |
| | (153 | ) | | (6.4 | )% | Midwest(b) | 750 | | | 747 | | | 3 | | | 0.4 | % | | 2,178 | | | 2,247 | | | (69) | | | (3.1) | % |
| New York | 291 |
| | 292 |
| | (1 | ) | | (0.3 | )% | | 810 |
| | 841 |
| | (31 | ) | | (3.7 | )% | New York | 285 | | | 291 | | | (6) | | | (2.1) | % | | 725 | | | 810 | | | (85) | | | (10.5) | % |
| ERCOT | 72 |
| | 98 |
| | (26 | ) | | (26.5 | )% | | 225 |
| | 216 |
| | 9 |
| | 4.2 | % | ERCOT | 147 | | | 72 | | | 75 | | | 104.2 | % | | 325 | | | 225 | | | 100 | | | 44.4 | % |
| Other Power Regions | 184 |
| | 180 |
| | 4 |
| | 2.2 | % | | 478 |
| | 607 |
| | (129 | ) | | (21.3 | )% | Other Power Regions | 225 | | | 184 | | | 41 | | | 22.3 | % | | 538 | | | 478 | | | 60 | | | 12.6 | % |
| Total electric revenue net of purchased power and fuel expense | 1,983 |
| | 2,101 |
| | (118 | ) | | (5.6 | )% | | 5,783 |
| | 6,412 |
| | (629 | ) | | (9.8 | )% | |
| Proprietary Trading | (1 | ) | | 5 |
| | (6 | ) | | (120.0 | )% | | 10 |
| | 39 |
| | (29 | ) | | (74.4 | )% | |
| Total electric revenues net of purchased power and fuel expense | | Total electric revenues net of purchased power and fuel expense | 1,998 | | | 1,983 | | | 15 | | | 0.8 | % | | 5,449 | | | 5,783 | | | (334) | | | (5.8) | % |
| Mark-to-market gains (losses) | 17 |
| | 71 |
| | (54 | ) | | (76.1 | )% | | (84 | ) | | (104 | ) | | 20 |
| | (19.2 | )% | Mark-to-market gains (losses) | 255 | | | 17 | | | 238 | | | 1,400.0 | % | | 472 | | | (84) | | | 556 | | | 661.9 | % |
| Other | 124 |
| | 121 |
| | 3 |
| | 2.5 | % | | 423 |
| | 469 |
| | (46 | ) | | (9.8 | )% | Other | 92 | | | 123 | | | (31) | | | (25.2) | % | | 390 | | | 433 | | | (43) | | | (9.9) | % |
| Total revenue net of purchased power and fuel expense | $ | 2,123 |
| | $ | 2,298 |
| | $ | (175 | ) | | (7.6 | )% | | $ | 6,132 |
| | $ | 6,816 |
| | $ | (684 | ) | | (10.0 | )% | Total revenue net of purchased power and fuel expense | $ | 2,345 | | | $ | 2,123 | | | $ | 222 | | | 10.5 | % | | $ | 6,311 | | | $ | 6,132 | | | $ | 179 | | | 2.9 | % |
_________
| |
(a) | Includes results of transactions with PECO, BGE, Pepco, DPL and ACE. |
| |
(b) | Includes results of transactions with ComEd. |
(a)Includes results of transactions with PECO, BGE, Pepco, DPL, and ACE.
(b)Includes results of transactions with ComEd.
Generation’s supply sources by region are summarized below:
| | | | | | | | | | | | | | | | | | | Three Months Ended
September 30, | | Variance | | % Change | | Nine Months Ended
September 30, | | Variance | | % Change |
| | Three Months Ended
September 30, | | Variance | | % Change | | Nine Months Ended
September 30, | | Variance | | % Change | |
| Supply source (GWhs) | 2019 | | 2018 | | 2019 | | 2018 | | |
| Supply Source (GWhs) | | Supply Source (GWhs) | 2020 | | 2019 | | Variance | | % Change | | 2020 | | 2019 | | Variance | | % Change |
Nuclear Generation(a) | | | | | | | | | | | | | | | | Nuclear Generation(a) | | | | | | | | |
| Mid-Atlantic | 15,281 |
| | 16,197 |
| | (916 | ) | | (5.7 | )% | | 44,436 |
| | 48,924 |
| | (4,488 | ) | | (9.2 | )% | Mid-Atlantic | 13,679 | | | 15,281 | | | (1,602) | | | (10.5) | % | | 39,630 | | | 44,436 | | | (4,806) | | | (10.8) | % |
| Midwest | 23,730 |
| | 23,834 |
| | (104 | ) | | (0.4 | )% | | 71,459 |
| | 70,532 |
| | 927 |
| | 1.3 | % | Midwest | 24,471 | | | 23,730 | | | 741 | | | 3.1 | % | | 71,929 | | | 71,459 | | | 470 | | | 0.7 | % |
| New York | 7,204 |
| | 6,518 |
| | 686 |
| | 10.5 | % | | 20,783 |
| | 19,758 |
| | 1,025 |
| | 5.2 | % | New York | 6,734 | | | 7,204 | | | (470) | | | (6.5) | % | | 19,296 | | | 20,783 | | | (1,487) | | | (7.2) | % |
| Total Nuclear Generation | 46,215 |
| | 46,549 |
| | (334 | ) | | (0.7 | )% | | 136,678 |
|
| 139,214 |
| | (2,536 | ) | | (1.8 | )% | Total Nuclear Generation | 44,884 | | | 46,215 | | | (1,331) | | | (2.9) | % | | 130,855 | | | 136,678 | | | (5,823) | | | (4.3) | % |
| Fossil and Renewables | | | | | | | | | | | | |
|
| |
|
| Fossil and Renewables | |
| Mid-Atlantic | 485 |
| | 853 |
| | (368 | ) | | (43.1 | )% | | 2,351 |
| | 2,660 |
| | (309 | ) | | (11.6 | )% | Mid-Atlantic | 304 | | | 485 | | | (181) | | | (37.3) | % | | 1,864 | | | 2,351 | | | (487) | | | (20.7) | % |
| Midwest | 262 |
| | 244 |
| | 18 |
| | 7.4 | % | | 981 |
| | 1,020 |
| | (39 | ) | | (3.8 | )% | Midwest | 196 | | | 262 | | | (66) | | | (25.2) | % | | 852 | | | 981 | | | (129) | | | (13.1) | % |
| New York | 3 |
| | 1 |
| | 2 |
| | 200.0 | % | | 4 |
| | 3 |
| | 1 |
| | 33.3 | % | New York | 1 | | | 3 | | | (2) | | | (66.7) | % | | 3 | | | 4 | | | (1) | | | (25.0) | % |
| ERCOT | 4,500 |
| | 3,137 |
| | 1,363 |
| | 43.4 | % | | 10,644 |
| | 8,389 |
| | 2,255 |
| | 26.9 | % | ERCOT | 4,394 | | | 4,500 | | | (106) | | | (2.4) | % | | 10,658 | | | 10,644 | | | 14 | | | 0.1 | % |
| Other Power Regions | 3,135 |
| | 3,628 |
| | (493 | ) | | (13.6 | )% | | 8,789 |
| | 10,692 |
| | (1,903 | ) | | (17.8 | )% | Other Power Regions | 2,794 | | | 3,135 | | | (341) | | | (10.9) | % | | 8,905 | | | 8,789 | | | 116 | | | 1.3 | % |
| Total Fossil and Renewables | 8,385 |
| | 7,863 |
| | 522 |
| | 6.6 | % | | 22,769 |
|
| 22,764 |
| | 5 |
| | — | % | Total Fossil and Renewables | 7,689 | | | 8,385 | | | (696) | | | (8.3) | % | | 22,282 | | | 22,769 | | | (487) | | | (2.1) | % |
| Purchased Power | | | | | | | | | | | | |
|
| |
|
| Purchased Power | |
| Mid-Atlantic | 5,235 |
| | 3,504 |
| | 1,731 |
| | 49.4 | % | | 10,359 |
| | 4,828 |
| | 5,531 |
| | 114.6 | % | Mid-Atlantic | 8,252 | | | 5,235 | | | 3,017 | | | 57.6 | % | | 17,924 | | | 10,359 | | | 7,565 | | | 73.0 | % |
| Midwest | 124 |
| | 174 |
| | (50 | ) | | (28.7 | )% | | 662 |
| | 733 |
| | (71 | ) | | (9.7 | )% | Midwest | 71 | | | 124 | | | (53) | | | (42.7) | % | | 595 | | | 662 | | | (67) | | | (10.1) | % |
| | ERCOT | 1,329 |
| | 1,811 |
| | (482 | ) | | (26.6 | )% | | 3,585 |
| | 5,504 |
| | (1,919 | ) | | (34.9 | )% | ERCOT | 1,104 | | | 1,329 | | | (225) | | | (16.9) | % | | 3,351 | | | 3,585 | | | (234) | | | (6.5) | % |
| Other Power Regions | 13,006 |
| | 12,705 |
| | 301 |
| | 2.4 | % | | 36,693 |
| | 32,731 |
| | 3,962 |
| | 12.1 | % | Other Power Regions | 14,512 | | | 13,006 | | | 1,506 | | | 11.6 | % | | 37,981 | | | 36,693 | | | 1,288 | | | 3.5 | % |
| Total Purchased Power | 19,694 |
| | 18,194 |
| | 1,500 |
| | 8.2 | % | | 51,299 |
|
| 43,796 |
| | 7,503 |
| | 17.1 | % | Total Purchased Power | 23,939 | | | 19,694 | | | 4,245 | | | 21.6 | % | | 59,851 | | | 51,299 | | | 8,552 | | | 16.7 | % |
Total Supply/Sales by Region | | | | | | | | | | | | |
|
| |
|
| |
Mid-Atlantic(b) | 21,001 |
| | 20,554 |
| | 447 |
| | 2.2 | % | | 57,146 |
| | 56,412 |
| | 734 |
| | 1.3 | % | Mid-Atlantic(b) | 22,235 | | | 21,001 | | | 1,234 | | | 5.9 | % | | 59,418 | | | 57,146 | | | 2,272 | | | 4.0 | % |
Midwest(b) | 24,116 |
| | 24,252 |
| | (136 | ) | | (0.6 | )% | | 73,102 |
| | 72,285 |
| | 817 |
| | 1.1 | % | Midwest(b) | 24,738 | | | 24,116 | | | 622 | | | 2.6 | % | | 73,376 | | | 73,102 | | | 274 | | | 0.4 | % |
| New York | 7,207 |
| | 6,519 |
| | 688 |
| | 10.6 | % | | 20,787 |
| | 19,761 |
| | 1,026 |
| | 5.2 | % | New York | 6,735 | | | 7,207 | | | (472) | | | (6.5) | % | | 19,299 | | | 20,787 | | | (1,488) | | | (7.2) | % |
| ERCOT | 5,829 |
| | 4,948 |
| | 881 |
| | 17.8 | % | | 14,229 |
| | 13,893 |
| | 336 |
| | 2.4 | % | ERCOT | 5,498 | | | 5,829 | | | (331) | | | (5.7) | % | | 14,009 | | | 14,229 | | | (220) | | | (1.5) | % |
| Other Power Regions | 16,141 |
| | 16,333 |
| | (192 | ) | | (1.2 | )% | | 45,482 |
| | 43,423 |
| | 2,059 |
| | 4.7 | % | Other Power Regions | 17,306 | | | 16,141 | | | 1,165 | | | 7.2 | % | | 46,886 | | | 45,482 | | | 1,404 | | | 3.1 | % |
| Total Supply/Sales by Region | 74,294 |
| | 72,606 |
| | 1,688 |
| | 2.3 | % | | 210,746 |
|
| 205,774 |
| | 4,972 |
| | 2.4 | % | Total Supply/Sales by Region | 76,512 | | | 74,294 | | | 2,218 | | | 3.0 | % | | 212,988 | | | 210,746 | | | 2,242 | | | 1.1 | % |
_________
| |
(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. |
(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 three and nine months ended September 30, 2020 compared to 2019, and 2018, changes in RNF by region were as follows:
| | | | Increase/ (Decrease) | Three Months Ended
September 30, 2019 | Increase/ (Decrease) | Nine Months Ended
September 30, 2019 | | Increase/ (Decrease) | Three Months Ended
September 30, 2020 | Increase/ (Decrease) | Nine Months Ended September 30, 2020 |
| Mid-Atlantic | $ | (74 | ) | • decreased capacity prices • decreased revenue due to permanent cease of generation operations at Oyster Creek in Q3 2018 • lower realized energy prices, partially offset by • increased ZEC revenues due to the approval of the NJ ZEC program in Q2 2019
| $ | (325 | ) | • lower realized energy prices • decreased revenue due to permanent cease of generation operations at Oyster Creek in Q3 2018 • increased nuclear outage days primarily at Salem • decreased capacity prices, partially offset by • increased ZEC revenues due to the approval of the NJ ZEC program in Q2 2019 | Mid-Atlantic | $ | (98) | | • decreased revenue due to permanent cease of generation operations at TMI in the third quarter of 2019
• lower realized energy prices, partially offset by
• increase in new contracted load, offset by impacts of COVID-19
• increased capacity revenue | $ | (340) | | • decreased revenue due to permanent cease of generation operations at TMI in the third quarter of 2019
• decreased capacity revenue
• lower realized energy prices, partially offset by
• increase in new contracted load, offset by impacts of COVID-19
• increased ZEC revenues due to the approval of the NJ ZEC program in the second quarter of 2019 |
| Midwest | (21 | ) | • decreased capacity prices partially offset by • higher realized energy prices
| (153 | ) | • the absence of the revenue recognized in the first quarter 2018 related to ZECs generated in Illinois from June through December 2017, partially offset by • higher realized energy prices and • decreased nuclear outage days | Midwest | 3 | | • increase in total ISO sales offset by impacts of COVID-19
• decreased nuclear outage days
• increased capacity revenue, partially offset by
• lower realized energy prices | (69) | | • decreased capacity revenue
• lower realized energy prices, partially offset by
• increase in total ISO sales offset by impacts of COVID-19
• decreased nuclear outage days |
| New York | (1 | ) | • lower realized energy prices • decreased capacity prices, partially offset by • increased ZEC revenues due to higher ZEC prices and increased output at Fitzpatrick • decreased nuclear outage days | (31 | ) | • lower realized energy prices • decreased capacity prices, partially offset by • increased ZEC revenues due to higher ZEC prices and increased output at Fitzpatrick • decreased nuclear outage days
| New York | (6) | | • increased nuclear outage days
• decreased ZEC revenues due to increased nuclear outage days
• lower realized energy prices, partially offset by
• increase in new contracted load, offset by impacts of COVID-19
• increased capacity revenue | (85) | | • increased nuclear outage days
• decreased ZEC revenues due to increased nuclear outage days
• lower realized energy prices,
• decreased load due to COVID-19 offset by new contracted load, partially offset by
• increased capacity revenue |
| ERCOT | (26 | ) | • decrease due to higher procurement costs for owned and contracted assets | 9 |
| • higher realized energy prices, partially offset by • higher procurements costs for owned and contracted assets | ERCOT | 75 | | • higher portfolio optimization
• lower procurement costs for owned and contracted assets | 100 | | • higher portfolio optimization
• lower procurement costs for owned and contracted assets |
| Other Power Regions | 4 |
| • higher realized energy prices, partially offset by • decreased capacity prices | (129 | ) | • lower realized energy prices • decreased capacity prices | Other Power Regions | 41 | | • increase in new contracted load, offset by impacts of COVID-19
• higher portfolio optimization, partially offset by
• decreased capacity revenue
• lower realized energy prices | 60 | | • increase in new contracted load, offset by impacts of COVID-19
• higher portfolio optimization, partially offset by
• decreased capacity revenue
• lower realized energy prices |
| Proprietary Trading | (6 | ) | • congestion activity | (29 | ) | • congestion activity | |
Mark-to-market(a) | (54 | ) | • gains on economic hedging activities of $17 million in 2019 compared to gains of $71 million in 2018 | 20 |
| • losses on economic hedging activities of $84 million in 2019 compared to losses of $104 million in 2018 | Mark-to-market(a) | 238 | | • gains on economic hedging activities of $255 million in 2020 compared to gains of $17 million in 2019 | 556 | | • gains on economic hedging activities of $472 million in 2020 compared to losses of $84 million in 2019 |
| Other | 3 |
| • no significant changes | (46 | ) | • the impacts of declining natural gas prices, partially offset by • decrease in accelerated nuclear fuel amortization associated with announced early plant retirements | Other | (31) | | • decreased revenue related to the energy efficiency business
• increase in accelerated nuclear fuel amortization associated with announced early plant retirements | (43) | | • decreased revenue related to the energy efficiency business
• increase in accelerated nuclear fuel amortization associated with announced early plant retirements |
| Total | $ | (175 | ) | | $ | (684 | ) | | Total | $ | 222 | | | $ | 179 | | |
_________
| |
(a) | See Note 10 — Derivative Financial Instruments for additional information on mark-to-market losses. |
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. 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.
| | | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2019 | | 2018 | | 2019 | | 2018 | | 2020 | | 2019 | | 2020 | | 2019 |
| Nuclear fleet capacity factor | 95.5 | % | | 93.6 | % | | 95.9 | % | | 94.4 | % | Nuclear fleet capacity factor | 96.0 | % | | 95.5 | % | | 95.1 | % | | 95.9 | % |
| Refueling outage days | 15 |
| | 36 |
| | 145 |
| | 198 |
| Refueling outage days | 17 | | | 15 | | | 203 | | | 145 | |
| Non-refueling outage days | 15 |
| | 12 |
| | 43 |
| | 20 |
| Non-refueling outage days | 4 | | | 15 | | | 15 | | | 43 | |
The changes in Operating and maintenance expense consisted of the following:
|
| | | | | | | |
| | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 |
| | Increase (Decrease) | | Increase (Decrease) |
Labor, other benefits, contracting, materials(a) | $ | (77 | ) | | $ | (135 | ) |
| Nuclear refueling outage costs, including the co-owned Salem plants | (35 | ) | | (52 | ) |
| Corporate allocations | (12 | ) | | (41 | ) |
Insurance(b) | — |
| | 31 |
|
| Merger and integration costs | — |
| | (5 | ) |
Plant retirements and divestitures(c) | (78 | ) | | (164 | ) |
| Change in environmental liabilities | 13 |
| | 6 |
|
ARO update(d) | (66 | ) | | (66 | ) |
Asset Impairments(e) | (6 | ) | | (38 | ) |
| Pension and non-pension postretirement benefits expense | (11 | ) | | (44 | ) |
| Allowance for uncollectible accounts | (1 | ) | | (18 | ) |
| Accretion expense | (11 | ) | | (28 | ) |
| Other | 1 |
| | (2 | ) |
| Decrease in Operating and maintenance expense | $ | (283 | ) | | $ | (556 | ) |
| | | | | | | | | | | |
| Three Months Ended
September 30, 2020 | | Nine Months Ended September 30, 2020 |
| | Increase (Decrease) | | Increase (Decrease) |
| Asset impairments | $ | 499 | | | $ | 504 | |
| Plant retirements and divestitures | 137 | | | 206 | |
| ARO update | 65 | | | 65 | |
| Change in environmental liabilities | 22 | | | 24 | |
| COVID-19 direct costs | 10 | | | 33 | |
Credit loss expense(a) | 2 | | | 19 | |
| Litigation settlements | — | | | 26 | |
| | | |
| Nuclear refueling outage costs, including the co-owned Salem plants | (3) | | | 52 | |
| Accretion expense | (5) | | | (20) | |
| | | |
| Pension and non-pension postretirement benefits expense | (6) | | | (15) | |
| Corporate allocations | (12) | | | (40) | |
| Travel costs | (13) | | | (25) | |
Labor, other benefits, contracting and materials(b) | (39) | | | (196) | |
| Other | (7) | | | (15) | |
| Increase in operating and maintenance expense | $ | 650 | | | $ | 618 | |
_________
| |
(a) | Primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek, lower labor costs resulting from previous cost management programs, and lower pension and OPEB costs. |
| |
(b) | Primarily reflects the absence of a supplemental NEIL insurance distribution received in the first quarter of 2018. |
| |
(c) | Primarily due to the benefit recorded in the first quarter of 2019 for the remeasurement of the TMI ARO and the absence of a charge associated with the remeasurement of the Oyster Creek ARO in the third quarter of 2018. |
| |
(d) | Primarily reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units. |
| |
(e) | Primarily due to the impairment of certain wind projects recorded in the second quarter of 2018. |
(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 Amortizationamortization expense for the three months ended September 30, 2020 compared to the same period in 2019 increased primarily due to the accelerated depreciation and amortization associated with Generation's decision to early retire the Byron and Dresden nuclear facilities and for the nine months ended September 30, 2020 compared to the same period in 2019 decreased primarily due to the permanent cease of generation operations at TMI partially offset by the accelerated depreciation and amortization associated with Generation's decision to early retire the Byron and Dresden nuclear facilities.
Taxes other than income taxes for the three and nine months ended September 30, 2020 compared to the same period in 2019 decreased primarily due to decreased sales and power usage.
(Loss) Gain on sales of assets and businesses for the three months ended September 30, 2020 compared to the same period in 2019 increased primarily due to a loss on Generation's sale of Oyster Creek in the third quarter of 2019 and for the nine months ended September 30, 2020 compared to the same period in 2019
decreased primarily due to Generation's gain on sale of certain wind assets in the second quarter of 2019 partially offset by the loss on sale of Oyster Creek.
Interest Expense for the three and nine months ended September 30, 20192020 compared to the same period in 20182019 decreased primarilyprimarily due to the permanent ceaseredemption of generation operations at Oyster Creeklong-term debt in the third quarter of 2018.2020.
Gain (Loss) on Sales of Assets and Businesses for the three months ended September 30, 2019 compared to the same period in 2018 decreased primarily due to Generation's sale of Oyster Creek. Gain (loss) on sales of
assets and businesses for the nine months ended September 30, 2019 compared to the same period in 2018 decreased primarily due to Generation's sale of its electrical contracting business in the first quarter of 2018.
Other, net for the three months ended September 30, 20192020 compared to the samesame period in 2018 decreased2019 increased and for the nine months ended September 30, 20192020 compared to the same period in 2018 increased due2019 decreased due to activity associated with NDT funds as described in the table below:
| | | | | | | | | | | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | 2020 | | 2019 | | 2020 | | 2019 |
| | 2019 | | 2018 | | 2019 | | 2018 | |
Net unrealized gains (losses) on NDT funds(a) | $ | 55 |
|
| $ | 72 |
| | $ | 236 |
| | $ | (143 | ) | |
Net unrealized gains on NDT funds(a) | | Net unrealized gains on NDT funds(a) | $ | 254 | |
| $ | 55 | | | $ | 1 | | | $ | 236 | |
Net realized gains on sale of NDT funds(a) | 9 |
| | 29 |
| | 231 |
| | 164 |
| Net realized gains on sale of NDT funds(a) | — | | | 9 | | | 58 | | | 231 | |
Interest and dividend income on NDT funds(a) | 24 |
| | 29 |
| | 85 |
| | 93 |
| Interest and dividend income on NDT funds(a) | 23 | | | 24 | | | 69 | | | 85 | |
Contractual elimination of income tax expense(b) | 31 |
| | 29 |
| | 150 |
| | 24 |
| Contractual elimination of income tax expense(b) | 89 | | | 31 | | | 46 | | | 150 | |
| Other | 9 |
| | 20 |
| | 27 |
| | 26 |
| Other | 1 | | | 9 | | | 25 | | | 27 | |
| Total other, net | $ | 128 |
| | $ | 179 |
| | $ | 729 |
| | $ | 164 |
| Total other, net | $ | 367 | | | $ | 128 | | | $ | 199 | | | $ | 729 | |
_________
| |
(a) | Unrealized gains (losses), realized gains and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement units. |
| |
(b) | Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement units. |
(a)Unrealized gains, realized gains and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement Units.
(b)Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement Units.
Effective income tax rates were were 45.7% and 17.4% and 20.1% for the three months ended September 30, 20192020 and 2018,2019, respectively. Generation's effective income tax rates were 28.6% were 7.7% and 13.8%28.6% for the nine months ended September 30, 20192020 and 2018,2019, respectively. The change is primarily relatedrelates to a reduction in renewable tax credits and one-time tax adjustments.settlements and an increase in tax credits. See Note 129 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.information
Equity in losses of unconsolidated affiliatesfor the three and nine months ended September 30, 20192020 compared to the same period in 2018 decreased2019 increased primarily due to the impairment of equity method investments in certain distributed energy companies.companies in the third quarter of 2019.
Net income attributable to noncontrolling interests for the three and nine months ended September 30, 20192020 compared to the same period in 20182019 increased primarily due to higher net gains on NDT fund investments for CENG and for the nine months ended September 30, 2020 compared to the same period in 2019 decreased primarily due to the offsetting noncontrolling interest impact of the impairment of equity methodlower unrealized losses on NDT fund investments in certain distributed energy companies.for CENG.
Results of Operations — ComEd
| | | | Three Months Ended
September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended
September 30, | | Favorable (Unfavorable) Variance | | Three Months Ended
September 30, | | Favorable
(Unfavorable)
Variance | | Nine Months Ended
September 30, | | Favorable
(Unfavorable)
Variance |
| | 2019 | | 2018 | | 2019 | | 2018 | | | 2020 | | 2019 | | 2020 | | 2019 | |
| Operating revenues | $ | 1,583 |
| | $ | 1,598 |
| | $ | (15 | ) | | $ | 4,342 |
| | $ | 4,508 |
| | $ | (166 | ) | Operating revenues | $ | 1,643 | | | $ | 1,583 | | | $ | 60 | | | $ | 4,499 | | | $ | 4,342 | | | $ | 157 | |
| Operating expenses | | Operating expenses | |
| Purchased power expense | 577 |
| | 619 |
| | 42 |
| | 1,469 |
| | 1,702 |
| | 233 |
| Purchased power expense | 606 | | | 577 | | | (29) | | | 1,557 | | | 1,469 | | | (88) | |
| Revenues net of purchased power expense | 1,006 |
| | 979 |
| | 27 |
| | 2,873 |
| | 2,806 |
| | 67 |
| |
| Other operating expenses | | | | | | | | | | | | |
| Operating and maintenance | 340 |
| | 337 |
| | (3 | ) | | 967 |
| | 974 |
| | 7 |
| Operating and maintenance | 321 | | | 340 | | | 19 | | | 1,173 | | | 967 | | | (206) | |
| Depreciation and amortization | 259 |
| | 237 |
| | (22 | ) | | 767 |
| | 696 |
| | (71 | ) | Depreciation and amortization | 294 | | | 259 | | | (35) | | | 841 | | | 767 | | | (74) | |
| Taxes other than income | 80 |
| | 82 |
| | 2 |
| | 228 |
| | 238 |
| | 10 |
| |
| Total other operating expenses | 679 |
| | 656 |
| | (23 | ) | | 1,962 |
| | 1,908 |
| | (54 | ) | |
| Taxes other than income taxes | | Taxes other than income taxes | 81 | | | 80 | | | (1) | | | 227 | | | 228 | | | 1 | |
| Total operating expenses | | Total operating expenses | 1,302 | | | 1,256 | | | (46) | | | 3,798 | | | 3,431 | | | (367) | |
| Gain on sales of assets | 1 |
| | — |
| | 1 |
| | 4 |
| | 5 |
| | (1 | ) | Gain on sales of assets | — | | | 1 | | | (1) | | | — | | | 4 | | | (4) | |
| Operating income | 328 |
| | 323 |
| | 5 |
| | 915 |
| | 903 |
| | 12 |
| Operating income | 341 | | | 328 | | | 13 | | | 701 | | | 915 | | | (214) | |
| Other income and (deductions) | | | | | | | | | | | | Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | (91 | ) | | (85 | ) | | (6 | ) | | (268 | ) | | (261 | ) | | (7 | ) | Interest expense, net | (95) | | | (91) | | | (4) | | | (287) | | | (268) | | | (19) | |
| Other, net | 8 |
| | 7 |
| | 1 |
| | 27 |
| | 21 |
| | 6 |
| Other, net | 10 | | | 8 | | | 2 | | | 32 | | | 27 | | | 5 | |
| Total other income and (deductions) | (83 | ) | | (78 | ) | | (5 | ) | | (241 | ) | | (240 | ) | | (1 | ) | Total other income and (deductions) | (85) | | | (83) | | | (2) | | | (255) | | | (241) | | | (14) | |
| Income before income taxes | 245 |
| | 245 |
| | — |
| | 674 |
| | 663 |
| | 11 |
| Income before income taxes | 256 | | | 245 | | | 11 | | | 446 | | | 674 | | | (228) | |
| Income taxes | 45 |
| | 52 |
| | 7 |
| | 130 |
| | 140 |
| | 10 |
| Income taxes | 60 | | | 45 | | | (15) | | | 142 | | | 130 | | | (12) | |
| Net income | $ | 200 |
| | $ | 193 |
| | $ | 7 |
| | $ | 544 |
| | $ | 523 |
| | $ | 21 |
| Net income | $ | 196 | | | $ | 200 | | | $ | (4) | | | $ | 304 | | | $ | 544 | | | $ | (240) | |
|
Three Months Ended September 30, 20192020 Compared toThree Months Ended September 30, 2018.2019. Net income remained relatively consistent for the three months ended September 30, 2019 as2020 compared to the same period in 2018.2019.
Nine Months Ended September 30, 20192020 Compared to Nine Months Ended September 30, 2018.2019. Net incomeincome increased $21decreased $240 million as compared to the same period in 2018,2019, primarily due to higher electric distribution,payments that ComEd will make under the Deferred Prosecution Agreement, an impairment charge resulting from acquisition of transmission assets, and energy efficiency formula rate earnings (reflecting the impacts of higher rate base, partially offset by lower allowed electric distribution ROE due to a decrease in treasury rates).
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fullyrates, partially offset by their impact on Purchased power expense, such as commodity, REC,higher electric distribution formula rate earnings (reflecting the impacts of higher rate base). See Note 14 — Commitments 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 haveContingencies of the choiceCombined Notes to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries but do impact Operating revenuesConsolidated Financial Statements for additional information related to supplied electricity.
The changes in RNFOperating revenues consisted of the following:
| | | | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 | | Three Months Ended
September 30, 2020 | | Nine Months Ended
September 30, 2020 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase | | Increase (Decrease) |
| Electric distribution | $ | 11 |
| | $ | 48 |
| Electric distribution | $ | 11 | | | $ | 31 | |
| Transmission | 5 |
| | 27 |
| Transmission | 8 | | | (4) | |
| Energy efficiency | 9 |
| | 36 |
| Energy efficiency | 10 | | | 29 | |
| Uncollectible accounts recovery, net | (3 | ) | | (5 | ) | |
| Other | 5 |
| | (39 | ) | Other | 16 | | | 21 | |
| | | | 45 | | | 77 | |
| Regulatory required programs | | Regulatory required programs | 15 | | | 80 | |
| Total increase | $ | 27 |
| | $ | 67 |
| Total increase | $ | 60 | | | $ | 157 | |
Revenue Decoupling. The demand for electricity is affected by weather conditions and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer or number of customers as a result of a change to the electric distribution formula rate pursuant to FEJA.
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. Electric distribution revenue increased duringfor the three and nine months ended September 30, 20192020 as
compared to the same period in 2018, primarily2019, due to the impact of higher rate base and increased depreciation expenses,higher fully recoverable costs, offset by lower allowed ROE due to a decrease in treasury rates. See Note 62 — 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 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 revenuerevenue increased for the three months ended September 30, 2019 as2020 compared to the same period in 2018,2019, primarily due to the impact of higher rate baseincreased peak load and higher fully recoverable costs. Transmission revenue increasedTransmission revenue decreased for the nine months ended September 30, 2019 as2020 compared to the same period in 2018,2019, primarily due to the impact of increaseddecreased peak load higher rate base, andpartially offset by higher fully recoverable costs. See Note 62 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Energy Efficiency Revenue. FEJA provides 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. UnderUnder FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the three and nine months ended September 30, 20192020 as compared to the same period in 2018,2019, primarily due to the impact of higher rate base and increased regulatory asset amortization.amortization which is fully recoverable. See Depreciation and amortization expense discussions below and Note 62 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Uncollectible Accounts Recovery, NetOther Revenue represents recoveries under the uncollectible accounts tariff. See Operating and maintenance expense discussion below for additional information on this tariff.
Other revenueprimarily includes rental revenue, revenue relatedassistance provided to late payment charges,other utilities through mutual assistance revenues, and recoveries of environmental costs associated with MGP sites.programs. The increase in Other revenue remained consistentrevenue for the three and nine months ended September 30, 20192020 as compared to the same period in 2018. The decrease in Other revenue for the nine months ended September 30, 2019, as compared to the same period in 2018 primarily reflects absence of mutual assistance revenues associated with hurricane and winter storm restoration efforts that occurredefforts.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, and costs related to electricity, ZEC and REC procurement. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Q1 2018. An equalPurchased power and offsetting amount was included infuel expense, Operating and maintenance expense, Depreciation and amortization 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 but impact Operating revenues related to supplied electricity. Drivers of Operating revenues related to electricity, ZEC and REC procurement costs, and participation in customer choice programs are fully offset by their impact on Purchased power and fuel expense. ComEd recovers electricity, ZEC, and REC procurement costs from customers without mark-up.
See Note 184 — 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 consisted of the following:
| | | | | | | | | | | |
| Three Months Ended
September 30, 2020 | | Nine Months Ended
September 30, 2020 |
| Increase (Decrease) | | (Decrease) Increase |
| Labor, other benefits, contracting and materials | $ | 2 | | | $ | (7) | |
| Pension and non-pension postretirement benefits expense | 1 | | | 5 | |
Deferred Prosecution Agreement payments(a) | — | | | 200 | |
| | | |
| | | |
| | | |
| BSC costs | (7) | | | 9 | |
Storm-related costs(b) | (12) | | | (10) | |
Other(c) | 1 | | | 11 | |
| (15) | | | 208 | |
Regulatory required programs(d) | (4) | | | (2) | |
| | | |
| Total (decrease) increase | $ | (19) | | | $ | 206 | |
|
| | | | | | | |
| | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 |
| | Increase (Decrease) | | Increase (Decrease) |
| Baseline | | | |
Labor, other benefits, contracting and materials(a) | $ | — |
| | $ | (4 | ) |
Pension and non-pension postretirement benefits expense(b) | (8 | ) | | (28 | ) |
| Storm-related costs | 7 |
| | 25 |
|
Uncollectible accounts expense — recovery, net(c) | (3 | ) | | (5 | ) |
| BSC costs | 12 |
| | 6 |
|
Other(a) | (5 | ) | | (1 | ) |
| Total increase (decrease) | $ | 3 |
| | $ | (7 | ) |
_________(a)See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
| |
(a) | Reflects absence of mutual assistance expenses. An equal and offsetting decrease has been recognized in Operating revenues for the period presented. |
| |
(b) | Primarily reflects an increase in discount rates and the favorable impacts of the merger of two of Exelon’s pension plans effective in January 2019, partially offset by lower than expected asset returns in 2018. |
| |
(c) | ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. During the three and nine months ended September 30, 2019, ComEd recorded a net decrease in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting increase has been recognized in Operating revenues for the period presented. |
(b)For the three and nine months ended September 30, 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 nine months ended September 30, 2020, the increase primarily reflects 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. During the three and nine months ended September 30, 2020, ComEd recorded a net decrease in credit losses account due to the timing of regulatory cost recovery. An equal and offsetting amount has been recognized in Operating revenues for the period presented.
The changes in Depreciation and amortization expense consisted of the following:
| | | | | | | | | | | |
| Three Months Ended
September 30, 2020 | | Nine Months Ended
September 30, 2020 |
| Increase | | Increase |
Depreciation and amortization(a) | $ | 30 | | | $ | 58 | |
Regulatory asset amortization(b) | 5 | | | 16 | |
| | | |
| Total increase | $ | 35 | | | $ | 74 | |
|
| | | | | | | |
| | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 |
| | Increase | | Increase |
Depreciation and amortization(a) | $ | 15 |
| | $ | 45 |
|
Regulatory asset amortization(b) | 7 |
| | 26 |
|
| Total increase | $ | 22 |
| | $ | 71 |
|
_________(a)Reflects ongoing capital expenditures and increased amortization related to the August 2020 storm regulatory asset.
| |
(a) | Reflects ongoing capital expenditures and higher depreciation rates effective January 2019. |
| |
(b) | Includes amortization of ComEd's energy efficiency formula rate regulatory asset. |
(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
Effective income tax raterates waswere 23.4% and 18.4% and 21.2% for the three months ended September 30, 2020 and 2019, respectively, and 2018, respectively. Effective income tax rate was31.8% and 19.3% and 21.1% for the nine months ended September 30, 20192020 and 2018,2019, respectively. See Note 129 — 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
| | | | Three Months Ended
September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended
September 30, | | Favorable
(Unfavorable)
Variance | | Three Months Ended
September 30, | | Favorable
(Unfavorable)
Variance | | Nine Months Ended
September 30, | | Favorable
(Unfavorable)
Variance |
| | 2019 | | 2018 | | 2019 | | 2018 | | | 2020 | | 2019 | | 2020 | | 2019 | |
| Operating revenues | $ | 778 |
| | $ | 757 |
| | $ | 21 |
| | $ | 2,333 |
| | $ | 2,275 |
| | $ | 58 |
| Operating revenues | $ | 813 | | | $ | 778 | | | $ | 35 | | | $ | 2,306 | | | $ | 2,333 | | | $ | (27) | |
| Operating expenses | | Operating expenses | |
| Purchased power and fuel expense | 246 |
| | 263 |
| | 17 |
| | 767 |
| | 818 |
| | 51 |
| Purchased power and fuel expense | 269 | | | 246 | | | (23) | | | 768 | | | 767 | | | (1) | |
| Revenues net of purchased power and fuel expense | 532 |
| | 494 |
| | 38 |
| | 1,566 |
| | 1,457 |
| | 109 |
| |
| Other operating expenses | | | | | | | | | | | | |
| Operating and maintenance | 219 |
| | 219 |
| | — |
| | 643 |
| | 686 |
| | 43 |
| Operating and maintenance | 251 | | | 219 | | | (32) | | | 742 | | | 643 | | | (99) | |
| Depreciation and amortization | 83 |
| | 75 |
| | (8 | ) | | 247 |
| | 224 |
| | (23 | ) | Depreciation and amortization | 85 | | | 83 | | | (2) | | | 259 | | | 247 | | | (12) | |
| Taxes other than income | 47 |
| | 46 |
| | (1 | ) | | 126 |
| | 125 |
| | (1 | ) | |
| Total other operating expenses | 349 |
| | 340 |
| | (9 | ) | | 1,016 |
| | 1,035 |
| | 19 |
| |
| Gain on sales of assets | — |
| | — |
| | — |
| | — |
| | 1 |
| | (1 | ) | |
| Taxes other than income taxes | | Taxes other than income taxes | 53 | | | 47 | | | (6) | | | 131 | | | 126 | | | (5) | |
| Total operating expenses | | Total operating expenses | 658 | | | 595 | | | (63) | | | 1,900 | | | 1,783 | | | (117) | |
| | Operating income | 183 |
| | 154 |
| | 29 |
| | 550 |
| | 423 |
| | 127 |
| Operating income | 155 | | | 183 | | | (28) | | | 406 | | | 550 | | | (144) | |
| Other income and (deductions) | | | | | | | | | | | | Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | (33 | ) | | (32 | ) | | (1 | ) | | (100 | ) | | (96 | ) | | (4 | ) | Interest expense, net | (39) | | | (33) | | | (6) | | | (108) | | | (100) | | | (8) | |
| Other, net | 4 |
| | 2 |
| | 2 |
| | 11 |
| | 4 |
| | 7 |
| Other, net | 6 | | | 4 | | | 2 | | | 12 | | | 11 | | | 1 | |
| Total other income and (deductions) | (29 | ) | | (30 | ) | | 1 |
| | (89 | ) | | (92 | ) | | 3 |
| Total other income and (deductions) | (33) | | | (29) | | | (4) | | | (96) | | | (89) | | | (7) | |
| Income before income taxes | 154 |
| | 124 |
| | 30 |
| | 461 |
| | 331 |
| | 130 |
| Income before income taxes | 122 | | | 154 | | | (32) | | | 310 | | | 461 | | | (151) | |
| Income taxes | 14 |
| | (2 | ) | | (16 | ) | | 51 |
| | (5 | ) | | (56 | ) | Income taxes | (16) | | | 14 | | | 30 | | | (7) | | | 51 | | | 58 | |
| | Net income | $ | 140 |
| | $ | 126 |
| | $ | 14 |
| | $ | 410 |
| | $ | 336 |
| | $ | 74 |
| Net income | $ | 138 | | | $ | 140 | | | $ | (2) | | | $ | 317 | | | $ | 410 | | | $ | (93) | |
Three Months Ended September 30, 20192020 Compared to Three Months Ended September 30, 2018.2019. Net income increased by $14 millionremained relatively consistent primarily due to higher electric distribution rates that became effective January 2019 and higher natural gas distribution rates, partiallyfavorable weather conditions, offset by unfavorable weather conditions and volume.higher storm costs due to the August 2020 storm net of tax repairs.
Nine Months Ended September 30, 20192020 Compared to Nine Months Ended September 30, 2018.2019. Net income increaseddecreased by $74$93 million primarily due to higher electric distribution rates that became effective January 2019, higher natural gas distribution rates and lower storm costs, partially offset by unfavorable weather conditions, higher storm costs due to the June and volume.
Revenues NetAugust 2020 storms net of Purchased Powertax repairs, increased depreciation and Fuel Expense
There are certain driversamortization expense, and an increase in credit loss expense primarily as a result of Operating revenues that are fullysuspending customer disconnections offset by their impact on Purchased power and fuel expense such as commodity and REC procurement costs and participationthe regulatory asset recorded in customer choice programs. PECO 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 volumethird quarter of deliveries or RNF, but impact Operating revenues2020 related to supplied electricity and natural gas.
The changes in RNFOperating revenues consisted of the following:
| | | | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 | | Three Months Ended
September 30, 2020 | | Nine Months Ended
September 30, 2020 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) |
| | Electric | | Gas | | Total | | Electric | | Gas | | Total | | Electric | | Gas | | Total | | Electric | | Gas | | Total |
| Weather | $ | (3 | ) | | $ | (1 | ) | | $ | (4 | ) | | $ | (9 | ) | | $ | (6 | ) | | $ | (15 | ) | Weather | $ | 9 | | | $ | 1 | | | $ | 10 | | | $ | (15) | | | $ | (12) | | | $ | (27) | |
| Volume | (7 | ) | | 1 |
| | (6 | ) | | (11 | ) | | 6 |
| | (5 | ) | Volume | 6 | | | 1 | | | 7 | | | 1 | | | (6) | | | (5) | |
| Pricing | 42 |
| | — |
| | 42 |
| | 91 |
| | 14 |
| | 105 |
| Pricing | (6) | | | (3) | | | (9) | | | 2 | | | 2 | | | 4 | |
| Regulatory required programs | 13 |
| | 1 |
| | 14 |
| | 35 |
| | 6 |
| | 41 |
| |
| Transmission | (11 | ) | | — |
| | (11 | ) | | (17 | ) | | — |
| | (17 | ) | Transmission | 7 | | | — | | | 7 | | | 9 | | | — | | | 9 | |
| Other | 3 |
| | — |
| | 3 |
| | — |
| | — |
| | — |
| Other | (1) | | | — | | | (1) | | | (6) | | | (1) | | | (7) | |
| Total increase | $ | 37 |
| | $ | 1 |
| | $ | 38 |
| | $ | 89 |
| | $ | 20 |
| | $ | 109 |
| |
| | | 15 | | | (1) | | | 14 | | | (9) | | | (17) | | | (26) | |
| Regulatory required programs | | Regulatory required programs | 27 | | | (6) | | | 21 | | | 54 | | | (55) | | | (1) | |
| Total increase (decrease) | | Total increase (decrease) | $ | 42 | | | $ | (7) | | | $ | 35 | | | $ | 45 | | | $ | (72) | | | $ | (27) | |
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. During the three and nine months ended September 30, 20192020 compared to the same period in 2018, RNF2019, Operating revenues related to weather increased by the impact of favorable weather conditions in PECO's service territory. During the nine months ended September 30, 2020 compared to the same period in 2019, Operating revenues related to weather decreased due toby the impact of unfavorable weather conditions.conditions in PECO'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 three and nine months ended September 30, 20192020 compared to the same period in 20182019 and normal weather consisted of the following:
| | | Heating and Cooling Degree-Days | | | Normal | | % Change | Heating and Cooling Degree-Days | | | Normal | | % Change |
| Three Months Ended September 30, | 2019 | | 2018 | From 2018 | | 2019 vs. Normal | Three Months Ended September 30, | 2020 | | 2019 | From 2019 | | 2020 vs. Normal |
| Heating Degree-Days | 2 |
| | 13 |
| | 27 |
| | (84.6 | )% | | (92.6 | )% | Heating Degree-Days | 37 | | 2 | | 26 | | 1,750.0 | % | | 42.3 | % |
| Cooling Degree-Days | 1,143 |
| | 1,124 |
| | 1,001 |
| | 1.7 | % | | 14.2 | % | Cooling Degree-Days | 1,128 | | | 1,143 | | 1,004 | | (1.3) | % | | 12.4 | % |
| | | | | | | | | | | |
| Nine Months Ended September 30, | | | | | | | | | | Nine Months Ended September 30, | |
| Heating Degree-Days | 2,704 |
| | 2,892 |
| | 2,890 |
| | (6.5 | )% | | (6.4 | )% | Heating Degree-Days | 2,594 | | | 2,704 | | 2,876 | | (4.1) | % | | (9.8) | % |
| Cooling Degree-Days | 1,570 |
| | 1,506 |
| | 1,386 |
| | 4.2 | % | | 13.3 | % | Cooling Degree-Days | 1,504 | | | 1,570 | | 1,391 | | (4.2) | % | | 8.1 | % |
Volume. Electric volume, exclusive of the effects of weather, for the three and nine months ended September 30, 20192020, compared to the same period in 2018, decreased2019, increased on a net basis due to the impact of energy efficiency initiatives on customer usagesan increase in usage for residential commercial and industrial electric classes, partially offsetcustomers during COVID-19 further increased by the impact of customer growth. Electric volume, exclusive of the effects of weather, for the nine months ended September 30, 2020, compared to the same period in 2019, remained relatively consistent. Natural gas volume for the three and nine months ended September 30, 2019, compared to the same period in 2018, increased2019, remained relatively consistent. Natural gas volume for the nine months ended September 30, compared to the same period in 2019, decreased on a net basis due to customera decrease in usage for the commercial and economic growth.industrial natural gas classes during COVID-19.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Retail Deliveries to Customers (in GWhs) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended September 30, | | % Change | | Weather - Normal % Change(b) |
| 2020 | | 2019 | | | 2020 | | 2019 | |
| Residential | 4,477 | | 4,106 | | 9.0 | % | | 6.4 | % | | 10,874 | | 10,568 | | 2.9 | % | | 4.5 | % |
| Small commercial & industrial | 2,017 | | 2,203 | | (8.4) | % | | (9.4) | % | | 5,493 | | 6,093 | | (9.8) | % | | (8.4) | % |
| Large commercial & industrial | 3,791 | | 4,109 | | (7.7) | % | | (8.3) | % | | 10,393 | | 11,449 | | (9.2) | % | | (8.9) | % |
| Public authorities & electric railroads | 145 | | 183 | | (20.8) | % | | (20.8) | % | | 407 | | 560 | | (27.3) | % | | (27.2) | % |
Total electric retail deliveries(a) | 10,430 | | 10,601 | | (1.6) | % | | (3.2) | % | | 27,167 | | 28,670 | | (5.2) | % | | (4.2) | % |
| | | | | | | | | | | |
| As of September 30, |
| Number of Electric Customers | 2020 | | 2019 |
| Residential | 1,505,080 | | 1,489,046 |
| Small commercial & industrial | 154,183 | | 153,400 |
| Large commercial & industrial | 3,105 | | 3,104 |
| Public authorities & electric railroads | 10,149 | | 9,775 |
| Total | 1,672,517 | | 1,655,325 |
__________
(a)Reflects delivery volumes 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas Deliveries to Customers (in mmcf) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) |
| 2020 | | 2019 | | | 2020 | | 2019 | |
| Residential | 2,121 | | 2,109 | | 0.6 | % | | (4.3) | % | | 25,867 | | 26,678 | | (3.0) | % | | 0.7 | % |
| Small commercial & industrial | 2,157 | | 1,901 | | 13.5 | % | | 12.7 | % | | 13,020 | | 16,585 | | (21.5) | % | | (8.0) | % |
| Large commercial & industrial | 9 | | 10 | | (10.0) | % | | (13.4) | % | | 20 | | 46 | | (56.5) | % | | (16.5) | % |
| Transportation | 5,269 | | 5,395 | | (2.3) | % | | (4.2) | % | | 17,553 | | 19,087 | | (8.0) | % | | (6.9) | % |
Total natural gas retail deliveries(a) | 9,556 | | 9,415 | | 1.5 | % | | (1.1) | % | | 56,460 | | 62,396 | | (9.5) | % | | (3.8) | % |
| | | | | | | | | | | |
| | As of September 30, |
| Number of Natural Gas Customers | 2020 | | 2019 |
| Residential | 490,158 | | 484,676 |
| Small commercial & industrial | 44,138 | | 43,869 |
| Large commercial & industrial | 5 | | 2 |
| Transportation | 715 | | 735 |
| Total | 535,016 | | 529,282 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Electric Retail Deliveries to Customers (in GWhs) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended September 30, | | % Change | | Weather - Normal % Change(b) |
| 2019 | | 2018 | | | 2019 | | 2018 | |
| Residential | 4,106 |
| | 4,166 |
| | (1.4 | )% | | (0.8 | )% | | 10,568 |
| | 10,741 |
| | (1.6 | )% | | (0.5 | )% |
| Small commercial & industrial | 2,203 |
| | 2,315 |
| | (4.8 | )% | | (2.0 | )% | | 6,093 |
| | 6,273 |
| | (2.9 | )% | | (1.7 | )% |
| Large commercial & industrial | 4,109 |
| | 4,378 |
| | (6.1 | )% | | (6.3 | )% | | 11,449 |
| | 11,892 |
| | (3.7 | )% | | (3.9 | )% |
| Public authorities & electric railroads | 183 |
| | 189 |
| | (3.2 | )% | | (3.3 | )% | | 560 |
| | 568 |
| | (1.4 | )% | | (2.0 | )% |
Total electric retail deliveries(a) | 10,601 |
| | 11,048 |
| | (4.0 | )% | | (3.3 | )% | | 28,670 |
| | 29,474 |
| | (2.7 | )% | | (2.1 | )% |
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. |
| | | | | |
| | As of September 30, |
| Number of Electric Customers | 2019 | | 2018 |
| Residential | 1,489,046 |
| | 1,476,914 |
|
| Small commercial & industrial | 153,400 |
| | 152,253 |
|
| Large commercial & industrial | 3,104 |
| | 3,124 |
|
| Public authorities & electric railroads | 9,775 |
| | 9,561 |
|
| Total | 1,655,325 |
| | 1,641,852 |
|
_________
| |
(a) | Reflects delivery volumes 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. |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas Deliveries to Customers (in mmcf) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) |
| 2019 | | 2018 | | | 2019 | | 2018 | |
| Residential | 2,109 |
| | 2,099 |
| | 0.5 | % | | 7.9 | % | | 26,678 |
| | 28,562 |
| | (6.6 | )% | | 1.1 | % |
| Small commercial & industrial | 1,901 |
| | 1,776 |
| | 7.0 | % | | 15.1 | % | | 16,585 |
| | 15,792 |
| | 5.0 | % | | 1.2 | % |
| Large commercial & industrial | 10 |
| | 6 |
| | 66.7 | % | | 12.4 | % | | 46 |
| | 58 |
| | (20.7 | )% | | 6.0 | % |
| Transportation | 5,395 |
| | 5,693 |
| | (5.2 | )% | | (3.4 | )% | | 19,087 |
| | 19,242 |
| | (0.8 | )% | | 1.3 | % |
Total natural gas retail deliveries(a) | 9,415 |
| | 9,574 |
| | (1.7 | )% | | 2.5 | % | | 62,396 |
| | 63,654 |
| | (2.0 | )% | | 1.2 | % |
|
| | | | | |
| | As of September 30, |
| Number of Natural Gas Customers | 2019 | | 2018 |
| Residential | 484,676 |
| | 479,732 |
|
| Small commercial & industrial | 43,869 |
| | 43,638 |
|
| Large commercial & industrial | 2 |
| | 1 |
|
| Transportation | 735 |
| | 761 |
|
| Total | 529,282 |
| | 524,132 |
|
_________
| |
(a) | Reflects delivery volumes from customers purchasing natural gas directly from PECO 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. |
Pricing for the three and nine months ended September 30, 20192020 compared to the same period in 2018 increased2019 decreased primarily due to an increaselower overall effective rates due to increased usage across all major customer classes. Pricing for the nine months ended September 30, 2020 compared to the same period in electric distribution rates charged2019 remained relatively consistent.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to customers. The increaseyear based upon fluctuations in electric distribution ratesthe underlying costs and capital investments being recovered. PECO's transmission formula rate filing was effective January 1, 2019approved in accordance with the 2018 PAPUC approved electric distribution rate case settlement. Additionally, the increase represents revenue from higher natural gas distribution rates. See Note 6 — Regulatory Mattersfourth quarter of the Combined Notes to Consolidated Financial Statements for additional information.2019.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as 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. 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 but impact Operating revenues related to supplied electricity and natural gas. Drivers of Operating revenues related to commodity and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power and fuel expense. PECO recovers electricity, natural gas, and REC procurement costs from customers without mark-up.
Transmission Revenue.Other revenue Under a FERC approved formula, transmissionprimarily includes revenue varies from yearrelated to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenuelate payment charges. Other revenues for the three and nine months ended September 30, 20192020 compared to the same period in 20182019, decreased primarily dueas PECO ceased new late fees for all customers and restored service to lower income taxes and operating and maintenance expenses. See Note 6 — Regulatory Matterscustomers upon request who were disconnected in the last twelve months beginning March of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes rental revenue, revenue related to late payment charges and mutual assistance revenues.2020.
See Note 18—4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The increase of $23 million and $1 million for the three and nine months ended September 30, 2020 compared to the same period in 2019, respectively, in Purchased power and fuel expense isfullyoffset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
|
| | | | | | | |
| | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 |
| | Increase (Decrease) | | Increase (Decrease) |
| Baseline | | | |
| Labor, other benefits, contracting and materials | $ | (5 | ) | | $ | 4 |
|
Storm-related costs(a) | 8 |
| | (42 | ) |
| Pension and non-pension postretirement benefits expense | (1 | ) | | (4 | ) |
| BSC costs | 2 |
| | 4 |
|
| Other | (5 | ) | | (6 | ) |
| | (1 | ) | | (44 | ) |
| Regulatory Required Programs | | | |
| Energy efficiency | 1 |
| | 1 |
|
| Total decrease | $ | — |
| | $ | (43 | ) |
| | | | | | | | | | | |
| Three Months Ended
September 30, 2020 | | Nine Months Ended
September 30, 2020 |
| Increase (Decrease) | | (Decrease) Increase |
Storm-related costs(a) | $ | 28 | | | $ | 81 | |
| Labor, other benefits, contracting and materials | 13 | | | 9 | |
| Pension and non-pension postretirement benefits expense | (1) | | | (2) | |
| | | |
| | | |
Credit loss expense(b) | (3) | | | 16 | |
| Other | (5) | | | (5) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Total increase | $ | 32 | | | $ | 99 | |
__________
| |
(a) | Reflects decreased storm costs due to the March 2018 winter storms. |
(a)Reflects increased storm costs due to June and August 2020 storms.
(b)Increased credit loss expense for the nine months ended September 30, 2020 primarily as a result of suspending customer disconnections offset by the regulatory asset recorded in the third quarter of 2020 related to incremental credit loss expense, due to COVID-19. Decreased credit loss expense for the three months ended September 30, 2020 is due to the reversal of credit loss expense when the regulatory asset was recorded. See Note 2 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expenseconsisted of the following:
| | | | Three Months Ended September 30, 2019 | | Nine Months Ended
September 30, 2019 | | Three Months Ended September 30, 2020 | | Nine Months Ended
September 30, 2020 |
| | Increase | | Increase | | Increase | | Increase (Decrease) |
Depreciation and amortization(a) | $ | 7 |
| | $ | 21 |
| Depreciation and amortization(a) | $ | 2 | | | $ | 13 | |
| Regulatory asset amortization | 1 |
| | 2 |
| Regulatory asset amortization | — | | | (1) | |
| | Total increase | $ | 8 |
| | $ | 23 |
| Total increase | $ | 2 | | | $ | 12 | |
__________
| |
(a) | Depreciation and amortization increased primarily due to ongoing capital expenditures. |
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net increased $6 million and $8 million for the three and nine months ended September 30, 2020 compared to the same period in 2019, respectively, primarily due to the issuance of debt in June 2020.
Effective Income Tax Ratesincome tax rates were 9.1%(13.1)% and (1.6)%9.1% for the three months ended September 30, 20192020 and 2018,2019, respectively, and 11.1%(2.3)% and (1.5)%11.1% for the nine months ended September 30, 20192020 and 2018,2019, respectively. See Note 129 — 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 — BGE
| | | | Three Months Ended
September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended
September 30, | | Favorable (Unfavorable) Variance | | Three Months Ended
September 30, | | Favorable
(Unfavorable)
Variance | | Nine Months Ended
September 30, | | Favorable
(Unfavorable)
Variance |
| | 2019 | | 2018 | | 2019 | | 2018 | | | 2020 | | 2019 | | 2020 | | 2019 | |
| Operating revenues | $ | 703 |
| | $ | 731 |
| | $ | (28 | ) | | $ | 2,327 |
| | $ | 2,369 |
| | $ | (42 | ) | Operating revenues | $ | 731 | | | $ | 703 | | | $ | 28 | | | $ | 2,284 | | | $ | 2,327 | | | $ | (43) | |
| Operating expenses | | Operating expenses | |
| Purchased power and fuel expense | 235 |
| | 272 |
| | 37 |
| | 804 |
| | 881 |
| | 77 |
| Purchased power and fuel expense | 250 | | | 235 | | | (15) | | | 731 | | | 804 | | | 73 | |
| Revenues net of purchased power and fuel expense | 468 |
| | 459 |
| | 9 |
| | 1,523 |
| | 1,488 |
| | 35 |
| |
| Other operating expenses | | | | | | | | | | | | |
| Operating and maintenance | 196 |
| | 182 |
| | (14 | ) | | 569 |
| | 578 |
| | 9 |
| Operating and maintenance | 191 | | | 196 | | | 5 | | | 567 | | | 569 | | | 2 | |
| Depreciation and amortization | 116 |
| | 110 |
| | (6 | ) | | 368 |
| | 358 |
| | (10 | ) | Depreciation and amortization | 133 | | | 116 | | | (17) | | | 405 | | | 368 | | | (37) | |
| Taxes other than income | 65 |
| | 64 |
| | (1 | ) | | 195 |
| | 188 |
| | (7 | ) | |
| Total other operating expenses | 377 |
| | 356 |
| | (21 | ) | | 1,132 |
| | 1,124 |
| | (8 | ) | |
| Gain on sales of assets | — |
| | — |
| | — |
| | — |
| | 1 |
| | (1 | ) | |
| Taxes other than income taxes | | Taxes other than income taxes | 68 | | | 65 | | | (3) | | | 200 | | | 195 | | | (5) | |
| Total operating expenses | | Total operating expenses | 642 | | | 612 | | | (30) | | | 1,903 | | | 1,936 | | | 33 | |
| | Operating income | 91 |
| | 103 |
| | (12 | ) | | 391 |
| | 365 |
| | 26 |
| Operating income | 89 | | | 91 | | | (2) | | | 381 | | | 391 | | | (10) | |
| Other income and (deductions) | | | | | | | | | | | | Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | (31 | ) | | (27 | ) | | (4 | ) | | (89 | ) | | (78 | ) | | (11 | ) | Interest expense, net | (34) | | | (31) | | | (3) | | | (99) | | | (89) | | | (10) | |
| Other, net | 7 |
| | 5 |
| | 2 |
| | 18 |
| | 14 |
| | 4 |
| Other, net | 6 | | | 7 | | | (1) | | | 17 | | | 18 | | | (1) | |
| Total other income and (deductions) | (24 | ) | | (22 | ) | | (2 | ) | | (71 | ) | | (64 | ) | | (7 | ) | Total other income and (deductions) | (28) | | | (24) | | | (4) | | | (82) | | | (71) | | | (11) | |
| Income before income taxes | 67 |
| | 81 |
| | (14 | ) | | 320 |
| | 301 |
| | 19 |
| Income before income taxes | 61 | | | 67 | | | (6) | | | 299 | | | 320 | | | (21) | |
| Income taxes | 12 |
| | 18 |
| | 6 |
| | 59 |
| | 59 |
| | — |
| Income taxes | 8 | | | 12 | | | 4 | | | 26 | | | 59 | | | 33 | |
| Net income | $ | 55 |
| | $ | 63 |
| | $ | (8 | ) | | $ | 261 |
| | $ | 242 |
| | $ | 19 |
| Net income | $ | 53 | | | $ | 55 | | | $ | (2) | | | $ | 273 | | | $ | 261 | | | $ | 12 | |
|
Three Months Ended September 30, 20192020 Compared to Three Months Ended September 30, 2018. 2019. Net income decreased by $8 millionremained relatively consistent primarily due to an increase in various expenses, partially offset by higher electric and natural gas distribution rates that became effective January 2019.December 2019, offset by an increase in various expenses.
Nine Months Ended September 30, 20192020 Compared to Nine Months Ended September 30, 2018.2019. Net income increased by $19$12 million primarily due to higher natural gas and electric distribution rates that became effective JanuaryDecember 2019, and lower storm costs, partially offset by an increase in various expenses, including interest.
Revenues Net of Purchased Powerdepreciation and Fuel Expense.amortization 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 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: | | | | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 | | Three Months Ended
September 30, 2020 | | Nine Months Ended
September 30, 2020 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) |
| | Electric | | Gas | | Total | | Electric | | Gas | | Total | | Electric | | Gas | | Total | | Electric | | Gas | | Total |
| Distribution | $ | 2 |
| | $ | 7 |
| | $ | 9 |
| | $ | 7 |
| | $ | 48 |
| | $ | 55 |
| Distribution | $ | 8 | | | $ | 3 | | | $ | 11 | | | $ | 18 | | | $ | 38 | | | $ | 56 | |
| Transmission | | Transmission | 3 | | | — | | | 3 | | | (8) | | | — | | | (8) | |
| Other | | Other | (6) | | | (2) | | | (8) | | | (7) | | | (6) | | | (13) | |
| | | 5 | | | 1 | | | 6 | | | 3 | | | 32 | | | 35 | |
| Regulatory required programs | (1 | ) | | 1 |
| | — |
| | (6 | ) | | (3 | ) | | (9 | ) | Regulatory required programs | 21 | | | 1 | | | 22 | | | (57) | | | (21) | | | (78) | |
| Transmission | 2 |
| | — |
| | 2 |
| | (3 | ) | | — |
| | (3 | ) | |
| Other, net | — |
| | (2 | ) | | (2 | ) | | (4 | ) | | (4 | ) | | (8 | ) | |
| Total increase (decrease) | $ | 3 |
| | $ | 6 |
| | $ | 9 |
| | $ | (6 | ) | | $ | 41 |
| | $ | 35 |
| Total increase (decrease) | $ | 26 | | | $ | 2 | | | $ | 28 | | | $ | (54) | | | $ | 11 | | | $ | (43) | |
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 September 30, |
| Number of Electric Customers | 2020 | | 2019 |
| Residential | 1,187,498 | | | 1,174,188 | |
| Small commercial & industrial | 114,038 | | | 114,301 | |
| Large commercial & industrial | 12,428 | | | 12,296 | |
| Public authorities & electric railroads | 267 | | | 264 | |
| Total | 1,314,231 | | | 1,301,049 | |
|
| | | | | |
| | As of September 30, |
| Number of Electric Customers | 2019 | | 2018 |
| Residential | 1,174,188 |
| | 1,165,012 |
|
| Small commercial & industrial | 114,301 |
| | 114,082 |
|
| Large commercial & industrial | 12,296 |
| | 12,218 |
|
| Public authorities & electric railroads | 264 |
| | 263 |
|
| Total | 1,301,049 |
| | 1,291,575 |
|
| | | | As of September 30, | | As of September 30, |
| Number of Natural Gas Customers | 2019 | | 2018 | Number of Natural Gas Customers | 2020 | | 2019 |
| Residential | 636,030 |
| | 631,589 |
| Residential | 644,872 | | | 636,030 | |
| Small commercial & industrial | 38,129 |
| | 38,175 |
| Small commercial & industrial | 38,173 | | | 38,129 | |
| Large commercial & industrial | 6,005 |
| | 5,920 |
| Large commercial & industrial | 6,083 | | | 6,005 | |
| Total | 680,164 |
| | 675,684 |
| Total | 689,128 | | | 680,164 | |
Distribution Revenue increased for the three and nine months ended September 30, 2019,2020, compared to the same period in 2018,2019, primarily due to the impact of higher natural gas and electric distribution rates that became effective in JanuaryDecember 2019. See Note 62 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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 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 remained relatively consistent for the three and nine months ended September 30, 2019,2020, compared to the same period in 2018.2019, and decreased for the nine months ended September 30, 2020, compared to the same period in 2019, primarily due to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Operating and maintenance expense below and Note 62 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes revenue related to mutual assistance, administrative charges, off-system sales, and late payment charges. Other revenues decreased for the three and nine months ended September 30, 2020, compared to the same period in 2019, as BGE temporarily suspended customer disconnections for non-payment 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 but impact Operating revenues related to supplied electricity and natural gas. Drivers of Operating revenues related to commodity procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power and fuel expense. BGE recovers electricity, natural gas, and procurement costs from customers with a slight mark-up.
See Note 184 — Segment Information of the Combined Notes to the Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The increase of $15 million and decrease of $73 million for the three and nine months ended September 30, 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:
| | | | | | | | | | | |
| Three Months Ended
September 30, 2020 | | Nine Months Ended
September 30, 2020 |
| | (Decrease) Increase | | (Decrease) Increase |
| Labor, other benefits, contracting and materials | $ | (5) | | | $ | (3) | |
| Storm-related costs | 3 | | | (3) | |
| Pension and non-pension postretirement benefits expense | — | | | (1) | |
Credit loss expense(a) | 1 | | | 7 | |
| BSC costs | — | | | 4 | |
| Other | (5) | | | (5) | |
| (6) | | | (1) | |
| Regulatory required programs | 1 | | | (1) | |
| | | |
| Total decrease | $ | (5) | | | $ | (2) | |
| | | |
| | | |
| | | |
|
| | | | | | | |
| | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 |
| | Increase (Decrease) | | Increase (Decrease) |
| Baseline | | | |
Storm-related costs(a) | $ | (3 | ) | | $ | (26 | ) |
| Labor, other benefits, contracting and materials | 12 |
| | 16 |
|
| Pension and non-pension postretirement benefits expense | — |
| | 1 |
|
| Uncollectible accounts expense | (1 | ) | | (1 | ) |
| BSC costs | 1 |
| | 2 |
|
| Other | 5 |
| | — |
|
| | 14 |
| | (8 | ) |
| Regulatory Required Programs | | | |
| Other | — |
| | (1 | ) |
| Total increase (decrease) | $ | 14 |
| | $ | (9 | ) |
__________(a)Increased credit loss expense primarily as a result of suspending customer disconnections, offset by the regulatory asset recorded in the third quarter of 2020 related to incremental credit loss expense due to COVID-19. See Note 2 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
| |
(a) | For the nine months ended September 30, 2019, reflects decreased storm costs due to the March 2018 winter storms. |
The changes in Depreciation and amortization expense consisted of the following:
| | | | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 | | Three Months Ended
September 30, 2020 | | Nine Months Ended
September 30, 2020 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase | | Increase |
Depreciation and amortization(a) | $ | 4 |
| | $ | 15 |
| Depreciation and amortization(a) | $ | 9 | | | $ | 30 | |
| Regulatory asset amortization | 2 |
| | 3 |
| Regulatory asset amortization | — | | | 1 | |
| Regulatory required programs | — |
| | (8 | ) | Regulatory required programs | 8 | | | 6 | |
| | Total increase | $ | 6 |
| | $ | 10 |
| Total increase | $ | 17 | | | $ | 37 | |
_________
| |
(a) | Depreciation and amortization increased primarily due to ongoing capital expenditures. |
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net for the three and nine months ended September 30, 2020 and 2019, compared to the same period in 2018, increased due to the issuance of debt in September 2018.2019 and June 2020.
Effective income tax rates were 17.9%13.1% and 22.2%17.9% for the three months ended September 30, 20192020 and 2018,2019, respectively, and 18.4%8.7% and 19.6%18.4% for the nine months ended September 30, 2020 and 2019. The change for the nine months ended September 30, 2020 compared to the same period in 2019, and 2018, respectively.is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 122 — Regulatory Matters and Note 9 — 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. All material intercompany accounts and transactions have been eliminated in consolidation. See the resultsResults of operationsOperations for Pepco, DPL, and ACE for additional information.
| | | | Three Months Ended
September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended
September 30, | | Favorable (Unfavorable) Variance | | Three Months Ended
September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended
September 30, | | Favorable (Unfavorable) Variance |
| | 2019 | | 2018 | | 2019 | | 2018 | | | 2020 | | 2019 | | 2020 | | 2019 | |
| PHI | $ | 189 |
| | $ | 187 |
| | $ | 2 |
| | $ | 412 |
| | $ | 336 |
| | $ | 76 |
| PHI | $ | 216 | | | $ | 189 | | | $ | 27 | | | $ | 418 | | | $ | 412 | | | $ | 6 | |
| Pepco | 98 |
| | 89 |
| | 9 |
| | 217 |
| | 174 |
| | 43 |
| Pepco | 118 | | | 98 | | | 20 | | | 227 | | | 217 | | | 10 | |
| DPL | 33 |
| | 33 |
| | — |
| | 116 |
| | 90 |
| | 26 |
| DPL | 27 | | | 33 | | | (6) | | | 91 | | | 116 | | | (25) | |
| ACE | 63 |
| | 61 |
| | 2 |
| | 87 |
| | 76 |
| | 11 |
| ACE | 75 | | | 63 | | | 12 | | | 106 | | | 87 | | | 19 | |
Other(a) | (5 | ) | | 4 |
| | (9 | ) | | (8 | ) | | (4 | ) | | (4 | ) | Other(a) | (4) | | | (5) | | | 1 | | | (6) | | | (8) | | | 2 | |
_________
| |
(a) | Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities and other financing and investing activities. |
(a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.
Three Months Ended September 30, 20192020 Compared to Three Months Ended September 30, 2018. Net Income remained relatively consistent with the same period in 2018 primarily due to higher electric and natural gas distribution rates (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, partially offset by an increase in environmental liabilities and various expenses.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018. 2019. Net Income increased by $76 million primarily due to higher electric and natural gas distribution rates (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, lower contracting costs, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, lower uncollectible accounts expense, and lower write-offs of construction work in progress, partially offset by an increase in environmental liabilities and various expenses.
Results of Operations — Pepco
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance |
| 2019 | | 2018 | | | 2019 | | 2018 | |
| Operating revenues | $ | 642 |
| | $ | 628 |
| | $ | 14 |
| | $ | 1,748 |
| | $ | 1,708 |
| | $ | 40 |
|
| Purchased power expense | 181 |
| | 177 |
| | (4 | ) | | 513 |
| | 497 |
| | (16 | ) |
| Revenues net of purchased power expense | 461 |
| | 451 |
| | 10 |
| | 1,235 |
| | 1,211 |
| | 24 |
|
| Other operating expenses | | | | | | | | | | | |
| Operating and maintenance | 135 |
| | 136 |
| | 1 |
| | 364 |
| | 383 |
| | 19 |
|
| Depreciation and amortization | 95 |
| | 99 |
| | 4 |
| | 281 |
| | 286 |
| | 5 |
|
| Taxes other than income | 104 |
| | 104 |
| | — |
| | 286 |
| | 288 |
| | 2 |
|
| Total other operating expenses | 334 |
| | 339 |
| | 5 |
| | 931 |
| | 957 |
| | 26 |
|
| Operating income | 127 |
| | 112 |
| | 15 |
| | 304 |
| | 254 |
| | 50 |
|
| Other income and (deductions) | | | | |
| | | | | |
|
| Interest expense, net | (33 | ) | | (32 | ) | | (1 | ) | | (100 | ) | | (96 | ) | | (4 | ) |
| Other, net | 9 |
| | 7 |
| | 2 |
| | 22 |
| | 23 |
| | (1 | ) |
| Total other income and (deductions) | (24 | ) | | (25 | ) | | 1 |
| | (78 | ) | | (73 | ) | | (5 | ) |
| Income before income taxes | 103 |
| | 87 |
| | 16 |
| | 226 |
| | 181 |
| | 45 |
|
| Income taxes | 5 |
| | (2 | ) | | (7 | ) | | 9 |
| | 7 |
| | (2 | ) |
| Net income | $ | 98 |
| | $ | 89 |
| | $ | 9 |
| | $ | 217 |
| | $ | 174 |
| | $ | 43 |
|
Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018.Net income increased by $9$27 million primarily due to higher electric distribution rates primarily at DPL, higher transmission rates (net of the impact of the settlement agreement of ongoing transmission-related income tax regulatory liabilities), and decreased expense resulting from an absence of an increase in Maryland that became effectiveenvironmental liabilities, partially offset by an increase in DPL storm costs related to the August 2019,2020 storms.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019. Net Income increased by $6 million primarily due to higher electric distribution rates, in the Districthigher transmission rates (net of Columbia that became effective August 2018 (not reflecting the impact of TCJA)the settlement agreement of ongoing transmission-related income tax regulatory liabilities), higher transmission revenues due toand decreased expense resulting from an absence of an increase in the transmission ratesenvironmental liabilities and the highest daily peak load, the absencean expiration of the charge associated with a remeasurement of the Buzzard Point ARO,lease arrangement, partially offset by an increase in depreciation and amortization, an increase in DPL storm costs related to the August 2020 storms, an increase in credit loss expense primarily as a result of suspending customer disconnections offset by the regulatory asset recorded in the third quarter of 2020 related to incremental credit loss expense due to COVID-19, and unfavorable weather conditions in ACE and DPL Delaware's service territories.
Results of Operations — Pepco
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance |
| 2020 | | 2019 | | | 2020 | | 2019 | |
| Operating revenues | $ | 611 | | | $ | 642 | | | $ | (31) | | | $ | 1,650 | | | $ | 1,748 | | | $ | (98) | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Operating expenses | | | | | | | | | | | |
| Purchased power expense | 163 | | | 181 | | | 18 | | | 467 | | | 513 | | | 46 | |
| Operating and maintenance | 106 | | | 135 | | | 29 | | | 336 | | | 364 | | | 28 | |
| Depreciation and amortization | 96 | | | 95 | | | (1) | | | 282 | | | 281 | | | (1) | |
| Taxes other than income taxes | 100 | | | 104 | | | 4 | | | 279 | | | 286 | | | 7 | |
| Total operating expenses | 465 | | | 515 | | | 50 | | | 1,364 | | | 1,444 | | | 80 | |
| | | | | | | | | | | |
| Operating income | 146 | | | 127 | | | 19 | | | 286 | | | 304 | | | (18) | |
| Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | (35) | | | (33) | | | (2) | | | (103) | | | (100) | | | (3) | |
| Other, net | 10 | | | 9 | | | 1 | | | 28 | | | 22 | | | 6 | |
| Total other income and (deductions) | (25) | | | (24) | | | (1) | | | (75) | | | (78) | | | 3 | |
| Income before income taxes | 121 | | | 103 | | | 18 | | | 211 | | | 226 | | | (15) | |
| Income taxes | 3 | | | 5 | | | 2 | | | (16) | | | 9 | | | 25 | |
| Net income | $ | 118 | | | $ | 98 | | | $ | 20 | | | $ | 227 | | | $ | 217 | | | $ | 10 | |
Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019.Net income increased by $20 million primarily due to decreased expense resulting from an absence of an increase in environmental liabilities.
Nine Months Ended September 30, 20192020 Compared to Nine Months Ended September 30, 20182019.. Net income increased by $43$10 million primarily due to higher electric distribution rates in Maryland that became effective August 2019 and June 2018 (not reflecting the impactdecreased expense resulting from an absence of TCJA), higher electric distribution rates in the District of Columbia that became effective August 2018 (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission ratesenvironmental liabilities and the highest daily peak load, the absencean expiration of the charge associated with a remeasurement of the Buzzard Point ARO, lower contracting costs, and lower uncollectible accounts expense,lease arrangement, partially offset by an increase in environmental liabilities.
Revenues Netdepreciation and amortization and an increase in credit loss expense primarily as a result of Purchased Power Expense. There are certain drivers of Operating revenues that are fullysuspending customer disconnections offset by their impact on Purchased power expense, such as commodity and REC procurement costs and participationthe regulatory asset recorded 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 volumethird quarter of deliveries or RNF, but impact Operating revenues2020 related to supplied electricity.
The changes in RNFOperating revenues consisted of the following:
| | | | | | | | Three Months Ended
September 30, 2020 | | Nine Months Ended September 30, 2020 |
| | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 | | (Decrease) Increase | | Increase (Decrease) |
| | Increase (Decrease) | | Increase (Decrease) | |
| Volume | $ | 4 |
| | $ | 11 |
| |
| Distribution | 9 |
| | 19 |
| Distribution | $ | — | | | $ | 7 | |
| Regulatory required programs | (8 | ) | | (26 | ) | |
| Transmission | 2 |
| | 22 |
| Transmission | (4) | | | (33) | |
| Other | 3 |
| | (2 | ) | Other | (2) | | | (2) | |
| Total increase | $ | 10 |
| | $ | 24 |
| |
| | | (6) | | | (28) | |
| Regulatory required programs | | Regulatory required programs | (25) | | | (70) | |
| Total decrease | | Total decrease | $ | (31) | | | $ | (98) | |
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.
| | | | | | | | | | | |
| As of September 30, |
| Number of Electric Customers | 2020 | | 2019 |
| Residential | 828,578 | | | 814,412 | |
| Small commercial & industrial | 53,813 | | | 54,130 | |
| Large commercial & industrial | 22,485 | | | 22,240 | |
| Public authorities & electric railroads | 167 | | | 158 | |
| Total | 905,043 | | | 890,940 | |
Distribution Revenue exclusive of the effects of weather, increased for the three and nine months ended September 30, 20192020 compared to the same period in 2018, primarily due to the impact of residential customer growth.
|
| | | | | |
| | As of September 30, |
| Number of Electric Customers | 2019 | | 2018 |
| Residential | 814,412 |
| | 802,607 |
|
| Small commercial & industrial | 54,130 |
| | 53,700 |
|
| Large commercial & industrial | 22,240 |
| | 21,927 |
|
| Public authorities & electric railroads | 158 |
| | 147 |
|
| Total | 890,940 |
| | 878,381 |
|
Distribution Revenues increased for the three and nine months ended September 30, 2019, compared to the same period in 2018 primarily due to higher electric distribution rates in Maryland that became effective in August 2019 and June 2018 (not reflecting the impact of TCJA), higher electric distribution rates (not reflecting the impact of TCJA) in the District of Columbia that became effective in August 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 6 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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.2019.
Transmission Revenues. 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 revenues increaseddecreased for the three and nine months ended September 30, 20192020 compared to the same period in 20182019, primarily due to rate increases and an increase in the highest daily peak load.settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes. Other revenue decreased for the three and nine months ended September 30, 2020, compared to the same period in 2019, as Pepco temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored services to customers upon request who were disconnected in the last twelve months.
Seeee Note 184 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The decrease of $18 million and $46 million for the three and nine months ended September 30, 2020 compared to the same period 2019, respectively, 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:
| | | | | | | | | | | |
| Three Months Ended
September 30, 2020 | | Nine Months Ended September 30, 2020 |
| Increase (Decrease) | | Increase (Decrease) |
| Labor, other benefits, contracting and materials | $ | 4 | | | $ | 15 | |
Credit loss expense(a) | (2) | | | 6 | |
| Storm-related costs | — | | | (1) | |
| Pension and non-pension postretirement benefits expense | (2) | | | (5) | |
| BSC and PHISCO costs | (1) | | | (4) | |
| Expiration of lease arrangement | (4) | | | (12) | |
| Change in environmental liabilities | (23) | | | (23) | |
| Other | 1 | | | (3) | |
| (27) | | | (27) | |
| | | |
| Regulatory required programs | (2) | | | (1) | |
| Total decrease | $ | (29) | | | $ | (28) | |
|
| | | | | | | |
| | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 |
| | Increase (Decrease) | | Increase (Decrease) |
| Baseline | | | |
| Labor, other benefits, contracting and materials | $ | (2 | ) | | $ | (14 | ) |
| Pension and non-pension postretirement benefits expense | 2 |
| | 5 |
|
| Uncollectible accounts expense | 1 |
| | (4 | ) |
| Storm-related costs | 2 |
| | (1 | ) |
| BSC and PHISCO costs | (2 | ) | | (9 | ) |
| Other | (2 | ) | | 7 |
|
| | (1 | ) | | (16 | ) |
| | | | |
| Regulatory required programs | — |
| | (3 | ) |
| Total decrease | $ | (1 | ) | | $ | (19 | ) |
(a)Increased credit loss expense for the nine months ended September 30, 2020 primarily as a result of suspending customer disconnections, offset by the regulatory asset recorded in the third quarter of 2020 related to incremental credit loss expense due to COVID-19. Decreased credit loss expense for the three months ended September 30, 2020 is due to the reversal of credit loss expense when the regulatory asset was recorded. See Note 2 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:
| | | | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 | | Three Months Ended
September 30, 2020 | | Nine Months Ended September 30, 2020 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) |
Depreciation and amortization(a) | $ | 6 |
| | $ | 17 |
| Depreciation and amortization(a) | $ | 4 | | | $ | 13 | |
| Regulatory asset amortization | | Regulatory asset amortization | (1) | | | (1) | |
| Regulatory required programs | (10 | ) | | (22 | ) | Regulatory required programs | (2) | | | (11) | |
| Total decrease | $ | (4 | ) | | $ | (5 | ) | |
| Total increase | | Total increase | $ | 1 | | | $ | 1 | |
_________
| |
(a) | (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. |
Interest expense, net for the nine months ended September 30, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.
Effective income tax rates were 4.9%2.5% and (2.3)%4.9% for the three months ended September 30, 20192020 and 2018,2019, respectively, and 4.0%(7.6)% and 3.9%4.0% for the nine months ended September 30, 20192020 and 2018,2019, respectively. The increasechange is primarily duerelated to the accelerated amortizationsettlement agreement of certain deferredongoing transmission-related income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements.liabilities. See Note 122 — Regulatory Matters and Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
Results of Operations — DPL
| | | | Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance | | Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance |
| 2019 | | 2018 | | 2019 | | 2018 | | 2020 | | 2019 | | 2020 | | 2019 | |
| Operating revenues | $ | 319 |
| | $ | 328 |
| | $ | (9 | ) | | $ | 987 |
| | $ | 1,001 |
| | $ | (14 | ) | Operating revenues | $ | 337 | | | $ | 319 | | | $ | 18 | | | $ | 954 | | | $ | 987 | | | $ | (33) | |
| Operating expenses | | Operating expenses | |
| Purchased power and fuel expense | 127 |
| | 133 |
| | 6 |
| | 399 |
| | 425 |
| | 26 |
| Purchased power and fuel expense | 131 | | | 127 | | | (4) | | | 379 | | | 399 | | | 20 | |
| Revenues net of purchased power and fuel expense | 192 |
| | 195 |
| | (3 | ) | | 588 |
| | 576 |
| | 12 |
| |
| Other operating expenses |
|
| |
|
| | | |
|
| |
|
| | | |
| Operating and maintenance | 80 |
| | 82 |
| | 2 |
| | 240 |
| | 256 |
| | 16 |
| Operating and maintenance | 101 | | | 80 | | | (21) | | | 272 | | | 240 | | | (32) | |
| Depreciation and amortization | 46 |
| | 47 |
| | 1 |
| | 138 |
| | 135 |
| | (3 | ) | Depreciation and amortization | 48 | | | 46 | | | (2) | | | 143 | | | 138 | | | (5) | |
| Taxes other than income | 15 |
| | 15 |
| | — |
| | 43 |
| | 43 |
| | — |
| |
| Total other operating expenses | 141 |
| | 144 |
| | 3 |
| | 421 |
| | 434 |
| | 13 |
| |
| Taxes other than income taxes | | Taxes other than income taxes | 16 | | | 15 | | | (1) | | | 49 | | | 43 | | | (6) | |
| Total operating expenses | | Total operating expenses | 296 | | | 268 | | | (28) | | | 843 | | | 820 | | | (23) | |
| | Operating income | 51 |
| | 51 |
| | — |
| | 167 |
| | 142 |
| | 25 |
| Operating income | 41 | | | 51 | | | (10) | | | 111 | | | 167 | | | (56) | |
| Other income and (deductions) |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | (15 | ) | | (15 | ) | | — |
| | (45 | ) | | (42 | ) | | (3 | ) | Interest expense, net | (15) | | | (15) | | | — | | | (47) | | | (45) | | | (2) | |
| Other, net | 2 |
| | 2 |
| | — |
| | 10 |
| | 7 |
| | 3 |
| Other, net | 2 | | | 2 | | | — | | | 7 | | | 10 | | | (3) | |
| Total other income and (deductions) | (13 | ) | | (13 | ) | | — |
| | (35 | ) | | (35 | ) | | — |
| Total other income and (deductions) | (13) | | | (13) | | | — | | | (40) | | | (35) | | | (5) | |
| Income before income taxes | 38 |
|
| 38 |
| | — |
| | 132 |
|
| 107 |
| | 25 |
| Income before income taxes | 28 | | | 38 | | | (10) | | | 71 | | | 132 | | | (61) | |
| Income taxes | 5 |
| | 5 |
| | — |
| | 16 |
| | 17 |
| | 1 |
| Income taxes | 1 | | | 5 | | | 4 | | | (20) | | | 16 | | | 36 | |
| Net income | $ | 33 |
| | $ | 33 |
| | $ | — |
| | $ | 116 |
| | $ | 90 |
| | $ | 26 |
| Net income | $ | 27 | | | $ | 33 | | | $ | (6) | | | $ | 91 | | | $ | 116 | | | $ | (25) | |
Three Months Ended September 30, 20192020 Compared to Three Months Ended September 30, 20182019. Net income remained consistent withdecreased by $6 million primarily due to an increase in storm costs related to the same periodAugust 2020 storms in 2018.Delaware, partially offset by higher electric distribution rates.
Nine Months Ended September 30, 20192020 Compared to Nine Months Ended September 30, 20182019. Net income increaseddecreased by $26$25 million primarily due to higher transmission revenues due to an increase in storm costs related to the transmission ratesAugust 2020 storms in Delaware, an increase in depreciation and amortization, an increase in credit loss expense primarily as a result of suspending customer disconnections offset by the highest daily peak load,regulatory asset recorded in the third quarter of 2020 related to incremental credit loss expense due to COVID-19, and unfavorable weather conditions in DPL's Delaware service territory, partially offset by higher electric distribution rates in Maryland and Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), higher natural gas distribution rates in Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), and lower write-offs of construction work in progress.rates.
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:
| | | | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 | | Three Months Ended
September 30, 2020 | | Nine Months Ended
September 30, 2020 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) |
| | Electric | | Gas | | Total | | Electric | | Gas | | Total | | Electric | | Gas | | Total | | Electric | | Gas | | Total |
| Weather | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (2 | ) | | $ | (2 | ) | Weather | $ | (2) | | | $ | 2 | | | $ | — | | | $ | (6) | | | $ | 1 | | | $ | (5) | |
| Volume | — |
| | (1 | ) | | (1 | ) | | — |
| | 1 |
| | 1 |
| Volume | 3 | | | (1) | | | 2 | | | 2 | | | (4) | | | (2) | |
| Distribution | 1 |
| | — |
| | 1 |
| | 3 |
| | — |
| | 3 |
| Distribution | 4 | | | 2 | | | 6 | | | 7 | | | 5 | | | 12 | |
| Regulatory required programs | (2 | ) | | 1 |
| | (1 | ) | | (6 | ) | | 1 |
| | (5 | ) | |
| Transmission | 1 |
| | — |
| | 1 |
| | 18 |
| | — |
| | 18 |
| Transmission | 2 | | | — | | | 2 | | | (21) | | | — | | | (21) | |
| Other | (3 | ) | | — |
| | (3 | ) | | (3 | ) | | — |
| | (3 | ) | Other | 3 | | | — | | | 3 | | | 2 | | | (1) | | | 1 | |
| | | 10 | | | 3 | | | 13 | | | (16) | | | 1 | | | (15) | |
| Regulatory required programs | | Regulatory required programs | 5 | | | — | | | 5 | | | (17) | | | (1) | | | (18) | |
| Total increase (decrease) | $ | (3 | ) | | $ | — |
| | $ | (3 | ) | | $ | 12 |
| | $ | — |
| | $ | 12 |
| Total increase (decrease) | $ | 15 | | | $ | 3 | | | $ | 18 | | | $ | (33) | | | $ | — | | | $ | (33) | |
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland 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 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 three and nine months ended September 30, 20192020 compared to the same period in 2018, RNF2019, Operating revenues related to weather remained relatively consistent.decreased 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 three and nine months ended September 30, 20192020 compared to same period in 20182019 and normal weather consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Delaware Electric Service Territory | | | | | % Change |
| Three Months Ended September 30, | 2020 | | 2019 | | Normal | | 2020 vs. 2019 | | 2020 vs. Normal |
| Heating Degree-Days | 55 | | | 6 | | | 32 | | | 816.7 | % | | 71.9 | % |
| Cooling Degree-Days | 961 | | | 1,043 | | | 876 | | | (7.9) | % | | 9.7 | % |
| | | | | | | | | |
| | | | | % Change |
| Nine Months Ended September 30, | 2020 | | 2019 | | Normal | | 2020 vs. 2019 | | 2020 vs. Normal |
| Heating Degree-Days | 2,664 | | | 2,828 | | | 3,012 | | | (5.8) | % | | (11.6) | % |
| Cooling Degree-Days | 1,260 | | | 1,429 | | | 1,210 | | | (11.8) | % | | 4.1 | % |
|
| | | | | | | | | | | | | | |
| Delaware Electric Service Territory | | | | | % Change |
| Three Months Ended September 30, | 2019 | | 2018 | | Normal | | 2019 vs. 2018 | | 2019 vs. Normal |
| Heating Degree-Days | 6 |
| | 11 |
| | 33 |
| | (45.5 | )% | | (81.8 | )% |
| Cooling Degree-Days | 1,043 |
| | 1,027 |
| | 871 |
| | 1.6 | % | | 19.7 | % |
| | | | | | | | | | |
| | | | | | % Change |
| Nine Months Ended September 30, | 2019 | | 2018 | | Normal | | 2019 vs. 2018 | | 2019 vs. Normal |
| Heating Degree-Days | 2,828 |
| | 2,995 |
| | 3,017 |
| | (5.6 | )% | | (6.3 | )% |
| Cooling Degree-Days | 1,429 |
| | 1,376 |
| | 1,198 |
| | 3.9 | % | | 19.3 | % |
|
| | | | | | | | | | | | | | |
| Delaware Natural Gas Service Territory | | | | | % Change |
| Three Months Ended September 30, | 2019 | | 2018 | | Normal | | 2019 vs. 2018 | | 2019 vs. Normal |
| Heating Degree-Days | 6 |
| | 11 |
| | 41 |
| | (45.5 | )% | | (85.4 | )% |
| | | | | | | | | | |
| | | | | | % Change |
| Nine Months Ended September 30, | 2019 | | 2018 | | Normal | | 2019 vs. 2018 | | 2019 vs. Normal |
| Heating Degree-Days | 2,828 |
| | 2,995 |
| | 3,031 |
| | (5.6 | )% | | (6.7 | )% |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Delaware Natural Gas Service Territory | | | | | % Change |
| Three Months Ended September 30, | 2020 | | 2019 | | Normal | | 2020 vs. 2019 | | 2020 vs. Normal |
| Heating Degree-Days | 55 | | | 6 | | | 39 | | | 816.7 | % | | 41.0 | % |
| | | | | | | | | |
| | | | | % Change |
| Nine Months Ended September 30, | 2020 | | 2019 | | Normal | | 2020 vs. 2019 | | 2020 vs. Normal |
| Heating Degree-Days | 2,664 | | | 2,828 | | | 3,023 | | | (5.8) | % | | (11.9) | % |
Volume, exclusive of the effects of weather, remained relatively consistent for the three and nine months ended September 30, 20192020 compared to the same period in 2018.2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Retail Deliveries to Delaware Customers (in GWhs) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) |
| 2020 | | 2019 | | | | 2020 | | 2019 | | |
| Residential | 1,028 | | | 947 | | | 8.6 | % | | 12.3 | % | | 2,474 | | | 2,450 | | | 1.0 | % | | 5.4 | % |
| Small commercial & industrial | 373 | | | 387 | | | (3.6) | % | | (1.9) | % | | 943 | | | 1,013 | | | (6.9) | % | | (4.7) | % |
| Large commercial & industrial | 775 | | | 924 | | | (16.1) | % | | (15.4) | % | | 2,408 | | | 2,600 | | | (7.4) | % | | (6.5) | % |
| Public authorities & electric railroads | 6 | | | 8 | | | (25.0) | % | | (24.1) | % | | 23 | | | 25 | | | (8.0) | % | | (5.8) | % |
Total electric retail deliveries(a) | 2,182 | | | 2,266 | | | (3.7) | % | | (1.8) | % | | 5,848 | | | 6,088 | | | (3.9) | % | | (1.4) | % |
| | | | | | | | | | | | | | | | | | | As of September 30, |
| Electric Retail Deliveries to Delaware Customers (in GWhs) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | |
| 2019 | | 2018 | | 2019 | | 2018 | | |
| Number of Total Electric Customers (Maryland and Delaware) | | Number of Total Electric Customers (Maryland and Delaware) | 2020 | | 2019 |
| Residential | 947 |
| | 945 |
| | 0.2 | % | | 0.3 | % | | 2,450 |
| | 2,485 |
| | (1.4 | )% | | (0.6 | )% | Residential | 471,875 | | | 466,972 | |
| Small commercial & industrial | 387 |
| | 376 |
| | 2.9 | % | | 2.5 | % | | 1,013 |
| | 1,027 |
| | (1.4 | )% | | (1.3 | )% | Small commercial & industrial | 62,291 | | | 61,657 | |
| Large commercial & industrial | 924 |
| | 973 |
| | (5.0 | )% | | (5.2 | )% | | 2,600 |
| | 2,730 |
| | (4.8 | )% | | (4.8 | )% | Large commercial & industrial | 1,234 | | | 1,418 | |
| Public authorities & electric railroads | 8 |
| | 8 |
| | — | % | | (1.1 | )% | | 25 |
| | 25 |
| | — | % | | 1.1 | % | Public authorities & electric railroads | 610 | | | 616 | |
Total electric retail deliveries(a) | 2,266 |
| | 2,302 |
| | (1.6 | )% | | (1.7 | )% | | 6,088 |
| | 6,267 |
| | (2.9 | )% | | (2.6 | )% | |
| Total | | Total | 536,010 | | | 530,663 | |
177
|
| | | | | |
| | As of September 30, |
| Number of Total Electric Customers (Maryland and Delaware) | 2019 | | 2018 |
| Residential | 466,972 |
| | 463,017 |
|
| Small commercial & industrial | 61,657 |
| | 61,277 |
|
| Large commercial & industrial | 1,418 |
| | 1,400 |
|
| Public authorities & electric railroads | 616 |
| | 622 |
|
| Total | 530,663 |
| | 526,316 |
|
_________
| |
(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) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) |
| 2019 | | 2018 | | | | 2019 | | 2018 | | |
| Residential | 403 |
| | 360 |
| | 11.9 | % | | 11.8 | % | | 5,751 |
| | 5,801 |
| | (0.9 | )% | | 3.8 | % |
| Small commercial & industrial | 386 |
| | 309 |
| | 24.9 | % | | 22.9 | % | | 2,972 |
| | 2,831 |
| | 5.0 | % | | 8.9 | % |
| Large commercial & industrial | 407 |
| | 454 |
| | (10.4 | )% | | (10.4 | )% | | 1,372 |
| | 1,438 |
| | (4.6 | )% | | (4.5 | )% |
| Transportation | 1,212 |
| | 1,260 |
| | (3.8 | )% | | (3.5 | )% | | 4,905 |
| | 4,893 |
| | 0.2 | % | | 1.6 | % |
Total natural gas deliveries(a) | 2,408 |
| | 2,383 |
| | 1.0 | % | | 1.4 | % | | 15,000 |
| | 14,963 |
| | 0.2 | % | | 3.3 | % |
|
| | | | | |
| | As of September 30, |
| Number of Delaware Natural Gas Customers | 2019 | | 2018 |
| Residential | 124,944 |
| | 123,145 |
|
| Small commercial & industrial | 9,885 |
| | 9,798 |
|
| Large commercial & industrial | 18 |
| | 19 |
|
| Transportation | 158 |
| | 154 |
|
| Total | 135,005 |
| | 133,116 |
|
__________
| |
(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. |
(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) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) |
| 2020 | | 2019 | | | | 2020 | | 2019 | | |
| Residential | 441 | | | 403 | | | 9.4 | % | | (11.1) | % | | 5,256 | | | 5,751 | | | (8.6) | % | | (3.5) | % |
| Small commercial & industrial | 339 | | | 386 | | | (12.2) | % | | (20.8) | % | | 2,567 | | | 2,972 | | | (13.6) | % | | (9.1) | % |
| Large commercial & industrial | 402 | | | 407 | | | (1.2) | % | | (1.2) | % | | 1,265 | | | 1,372 | | | (7.8) | % | | (7.8) | % |
| Transportation | 1,231 | | | 1,212 | | | 1.6 | % | | — | % | | 4,811 | | | 4,905 | | | (1.9) | % | | (0.7) | % |
Total natural gas deliveries(a) | 2,413 | | | 2,408 | | | 0.2 | % | | (5.7) | % | | 13,899 | | | 15,000 | | | (7.3) | % | | (4.1) | % |
| | | | | | | | | | | |
| As of September 30, |
| Number of Delaware Natural Gas Customers | 2020 | | 2019 |
| Residential | 126,659 | | | 124,944 | |
| Small commercial & industrial | 9,885 | | | 9,885 | |
| Large commercial & industrial | 17 | | | 18 | |
| Transportation | 160 | | | 158 | |
| Total | 136,721 | | | 135,005 | |
__________
(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 three and nine months ended September 30, 20192020 compared to the same period in 20182019 primarily due to higher electric distribution rates (not reflecting the impact of TCJA) in Maryland and Delaware that became effective throughout 2018in July 2020 and higher natural gas distribution rates (not reflecting the impactDistribution System Improvement Charge (DSIC) fully implemented in the first quarter of TCJA) in Delaware that became effective throughout 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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.2020.
Transmission Revenues. 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 years. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increaseddecreased for the three and nine months ended September 30, 20192020 compared to the same period in 20182019 primarily due to rate increasesthe settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and an increaserecoveries 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 highest daily peak load.choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, but impact Operating revenues related to supplied electricity. Drivers of Operating revenues related to commodity and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up and natural gas costs from customers without mark-up.
See Note 184 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The increase of $4 million and decrease of $20 million for the three and nine months ended September 30, 2020, respectively, compared to the same period in 2019, 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:
| | | | | | | | | | | |
| Three Months Ended
September 30, 2020 | | Nine Months Ended
September 30, 2020 |
| Increase (Decrease) | | Increase (Decrease) |
| Labor, other benefits, contracting and materials | $ | 1 | | | $ | 8 | |
Credit loss expense(a) | 2 | | | 9 | |
| Storm-related costs | 17 | | | 20 | |
| Pension and non-pension postretirement benefits expense | (1) | | | (3) | |
| BSC and PHISCO costs | (1) | | | (3) | |
| Other | — | | | (2) | |
| 18 | | | 29 | |
| Regulatory required programs | 3 | | | 3 | |
| Total increase | $ | 21 | | | $ | 32 | |
|
| | | | | | | |
| | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 |
| | Increase (Decrease) | | Increase (Decrease) |
| Baseline | | | |
| Labor, other benefits, contracting and materials | $ | (2 | ) | | $ | 1 |
|
| Pension and non-pension postretirement benefits expense | 1 |
| | 3 |
|
| Uncollectible accounts expense | (3 | ) | | (4 | ) |
| Storm-related costs | 2 |
| | (1 | ) |
| BSC and PHISCO costs | (1 | ) | | (6 | ) |
| Write-offs of construction work in progress | — |
| | (7 | ) |
| Other | 1 |
| | (1 | ) |
| | (2 | ) | | (15 | ) |
| | | | |
| Regulatory required programs | — |
| | (1 | ) |
| Total decrease | $ | (2 | ) | | $ | (16 | ) |
(a)Increased credit loss expense primarily as a result of suspending customer disconnections, offset by the regulatory asset recorded in the third quarter of 2020 related to incremental credit loss expense due to COVID-19. See Note 2 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:
| | | | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 | | Three Months Ended
September 30, 2020 | | Nine Months Ended
September 30, 2020 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) |
Depreciation and amortization(a) | $ | 4 |
| | $ | 11 |
| Depreciation and amortization(a) | $ | 2 | | | $ | 7 | |
| Regulatory asset amortization | (1 | ) | | (1 | ) | |
| | Regulatory required programs | (4 | ) | | (7 | ) | Regulatory required programs | — | | | (2) | |
| Total increase (decrease) | $ | (1 | ) | | $ | 3 |
| |
| Total increase | | Total increase | $ | 2 | | | $ | 5 | |
_________
| |
(a) | (a)Depreciation and amortization increased primarily due to ongoing capital expenditures. |
Interest expense, net for the nine months ended September 30, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.
Effective income tax rates were 13.2%3.6% and 13.2% for the three months ended September 30, 20192020 and 2018,2019, respectively, and 12.1%(28.2)% and 15.9%12.1% for the nine months ended September 30, 20192020 and 2018,2019, respectively. The decrease for the nine months ended September 30, 20192020 is primarily duerelated to the accelerated amortizationsettlement agreement of certain deferredongoing transmission-related income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements.liabilities. See Note 122 — Regulatory Matters and Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
Results of Operations — ACE
| | | | Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance | | Three Months Ended September 30, | | Favorable (Unfavorable) Variance | | Nine Months Ended September 30, | | Favorable (Unfavorable) Variance |
| | 2019 | | 2018 | | 2019 | | 2018 | | | 2020 | | 2019 | | 2020 | | 2019 | |
| Operating revenues | $ | 419 |
| | $ | 406 |
| | $ | 13 |
| | $ | 966 |
| | $ | 981 |
| | $ | (15 | ) | Operating revenues | $ | 420 | | | $ | 419 | | | $ | 1 | | | $ | 952 | | | $ | 966 | | | $ | (14) | |
| | Operating expenses | | Operating expenses | |
| Purchased power expense | 210 |
| | 198 |
| | (12 | ) | | 479 |
| | 486 |
| | 7 |
| Purchased power expense | 211 | | | 210 | | | (1) | | | 469 | | | 479 | | | 10 | |
| Revenues net of purchased power expense | 209 |
| | 208 |
| | 1 |
| | 487 |
| | 495 |
| | (8 | ) | |
| Other operating expenses | | | | |
| | | | | |
| |
| Operating and maintenance | 86 |
| | 85 |
| | (1 | ) | | 241 |
| | 250 |
| | 9 |
| Operating and maintenance | 77 | | | 86 | | | 9 | | | 238 | | | 241 | | | 3 | |
| Depreciation and amortization | 43 |
| | 38 |
| | (5 | ) | | 114 |
| | 107 |
| | (7 | ) | Depreciation and amortization | 48 | | | 43 | | | (5) | | | 134 | | | 114 | | | (20) | |
| Taxes other than income | 1 |
| | 1 |
| | — |
| | 4 |
| | 4 |
| | — |
| |
| Total other operating expenses | 130 |
| | 124 |
| | (6 | ) | | 359 |
| | 361 |
| | 2 |
| |
| Taxes other than income taxes | | Taxes other than income taxes | 2 | | | 1 | | | (1) | | | 6 | | | 4 | | | (2) | |
| Total operating expenses | | Total operating expenses | 338 | | | 340 | | | 2 | | | 847 | | | 838 | | | (9) | |
| Gain on sale of assets | | Gain on sale of assets | — | | | — | | | — | | | 2 | | | — | | | 2 | |
| Operating income | 79 |
| | 84 |
| | (5 | ) | | 128 |
| | 134 |
| | (6 | ) | Operating income | 82 | | | 79 | | | 3 | | | 107 | | | 128 | | | (21) | |
| Other income and (deductions) | | | | |
| | | | | |
| Other income and (deductions) | | | | | | | | | | | |
| Interest expense, net | (15 | ) | | (16 | ) | | 1 |
| | (44 | ) | | (48 | ) | | 4 |
| Interest expense, net | (15) | | | (15) | | | — | | | (45) | | | (44) | | | (1) | |
| Other, net | 1 |
| | 1 |
| | — |
| | 5 |
| | 2 |
| | 3 |
| Other, net | 1 | | | 1 | | | — | | | 5 | | | 5 | | | — | |
| Total other income and (deductions) | (14 | ) |
| (15 | ) | | 1 |
| | (39 | ) |
| (46 | ) | | 7 |
| Total other income and (deductions) | (14) | | | (14) | | | — | | | (40) | | | (39) | | | (1) | |
| Income before income taxes | 65 |
|
| 69 |
| | (4 | ) | | 89 |
|
| 88 |
| | 1 |
| Income before income taxes | 68 | | | 65 | | | 3 | | | 67 | | | 89 | | | (22) | |
| Income taxes | 2 |
| | 8 |
| | 6 |
| | 2 |
| | 12 |
| | 10 |
| Income taxes | (7) | | | 2 | | | 9 | | | (39) | | | 2 | | | 41 | |
| Net income | $ | 63 |
| | $ | 61 |
| | $ | 2 |
| | $ | 87 |
| | $ | 76 |
| | $ | 11 |
| Net income | $ | 75 | | | $ | 63 | | | $ | 12 | | | $ | 106 | | | $ | 87 | | | $ | 19 | |
Three Months Ended September 30, 20192020 Compared to Three Months Ended September 30, 2018.2019. Net income remained relatively consistent withincreased by $12 million primarily due to an increase in transmission rates (net of the same period in 2018.impact of the settlement agreement of ongoing transmission-related income tax regulatory liabilities).
Nine Months Ended September 30, 20192020 Compared to Nine Months Ended September 30, 20182019.. Net income increased by $11$19 million primarily due to higher electric distribution rates that became effective April 2019 and higher transmission revenues due to an increase in the transmission rates and(net of the highest daily peak load,impact of the settlement agreement of ongoing transmission-related income tax regulatory liabilities), partially offset by an increase in depreciation and amortization, unfavorable weather conditions in ACE's service territory, and lower average residentialcommercial and industrial usage.
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. 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 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:
| | | | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 | | Three Months Ended
September 30, 2020 | | Nine Months Ended September 30, 2020 |
| | Increase (Decrease) | | Increase (Decrease) | | (Decrease) Increase | | (Decrease) Increase |
| Weather | $ | (4 | ) | | $ | (4 | ) | Weather | $ | (1) | | | $ | (5) | |
| Volume | (4 | ) | | (10 | ) | Volume | 1 | | | (5) | |
| Distribution | 16 |
| | 21 |
| Distribution | — | | | 20 | |
| Regulatory required programs | (12 | ) | | (28 | ) | |
| Transmission | 7 |
| | 15 |
| Transmission | (1) | | | (19) | |
| Other | (2 | ) | | (2 | ) | Other | 4 | | | 1 | |
| | | 3 | | | (8) | |
| | Regulatory required programs | | Regulatory required programs | (2) | | | (6) | |
| Total increase (decrease) | $ | 1 |
| | $ | (8 | ) | Total increase (decrease) | $ | 1 | | | $ | (14) | |
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. There was a decrease related to weather for the three and nine months ended September 30, 20192020 compared to same period in 20182019 due to the impact of unfavorable weather 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 three and nine months ended September 30, 20192020 compared to same period in 20182019 consisted of the following:
| | | Heating and Cooling Degree-Days | | | Normal | | % Change | Heating and Cooling Degree-Days | | | Normal | | % Change |
| Three Months Ended September 30, | 2019 | | 2018 | | 2019 vs. 2018 | | 2019 vs. Normal | Three Months Ended September 30, | 2020 | | 2019 | | 2020 vs. 2019 | | 2020 vs. Normal |
| Heating Degree-Days | 13 |
| | 1 |
| | 38 |
| | 1,200.0 | % | | (65.8 | )% | Heating Degree-Days | 58 | | | 13 | | | 36 | | | 346.2 | % | | 61.1 | % |
| Cooling Degree-Days | 980 |
| | 1,093 |
| | 831 |
| | (10.3 | )% | | 17.9 | % | Cooling Degree-Days | 989 | | | 980 | | | 839 | | | 0.9 | % | | 17.9 | % |
| | | | | | | | | | | |
| | | | Normal | | % Change | | | | Normal | | % Change |
| Nine Months Ended September 30, | 2019 | | 2018 | | 2019 vs. 2018 | | 2019 vs. Normal | Nine Months Ended September 30, | 2020 | | 2019 | | 2020 vs. 2019 | | 2020 vs. Normal |
| Heating Degree-Days | 2,899 |
| | 2,928 |
| | 3,080 |
| | (1.0 | )% | | (5.9 | )% | Heating Degree-Days | 2,618 | | | 2,899 | | | 3,069 | | | (9.7) | % | | (14.7) | % |
| Cooling Degree-Days | 1,330 |
| | 1,447 |
| | 1,129 |
| | (8.1 | )% | | 17.8 | % | Cooling Degree-Days | 1,300 | | | 1,330 | | | 1,143 | | | (2.3) | % | | 13.7 | % |
Volume, exclusive of the effects of weather, decreasedincreased for the three months ended September 30, 2020 and decreased for the nine months ended September 30, 20192020 compared to the same period in 2018,2019, primarily due to lower average residentialcommercial and industrial usage.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Retail Deliveries to Customers (in GWhs) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) |
| 2020 | | 2019 | | | | 2020 | | 2019 | | |
| Residential | 1,533 | | | 1,470 | | | 4.3 | % | | 5.4 | % | | 3,193 | | | 3,182 | | | 0.3 | % | | 3.1 | % |
| Small commercial & industrial | 397 | | | 431 | | | (7.9) | % | | (9.1) | % | | 967 | | | 1,055 | | | (8.3) | % | | (7.5) | % |
| Large commercial & industrial | 851 | | | 938 | | | (9.3) | % | | (9.6) | % | | 2,287 | | | 2,600 | | | (12.0) | % | | (11.6) | % |
| Public authorities & electric railroads | 9 | | | 10 | | | (10.0) | % | | (5.8) | % | | 33 | | | 34 | | | (2.9) | % | | (2.3) | % |
Total electric retail deliveries(a) | 2,790 | | | 2,849 | | | (2.1) | % | | (1.9) | % | | 6,480 | | | 6,871 | | | (5.7) | % | | (4.2) | % |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Electric Retail Deliveries to Customers (in GWhs) | Three Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) | | Nine Months Ended
September 30, | | % Change | | Weather - Normal % Change(b) |
| 2019 | | 2018 | | | | 2019 | | 2018 | | |
| Residential | 1,470 |
| | 1,548 |
| | (5.0 | )% | | (1.6 | )% | | 3,182 |
| | 3,363 |
| | (5.4 | )% | | (3.9 | )% |
| Small commercial & industrial | 431 |
| | 442 |
| | (2.5 | )% | | (0.5 | )% | | 1,055 |
| | 1,066 |
| | (1.0 | )% | | 0.1 | % |
| Large commercial & industrial | 938 |
| | 1,030 |
| | (8.9 | )% | | (7.9 | )% | | 2,600 |
| | 2,725 |
| | (4.6 | )% | | (4.2 | )% |
| Public authorities & electric railroads | 10 |
| | 10 |
| | — | % | | (3.9 | )% | | 34 |
| | 36 |
| | (5.6 | )% | | (5.9 | )% |
Total electric retail deliveries(a) | 2,849 |
| | 3,030 |
| | (6.0 | )% | | (3.7 | )% | | 6,871 |
| | 7,190 |
| | (4.4 | )% | | (3.4 | )% |
| | | | As of September 30, | | As of September 30, |
| Number of Electric Customers | 2019 | | 2018 | Number of Electric Customers | 2020 | | 2019 |
| Residential | 493,720 |
| | 489,961 |
| Residential | 497,222 | | | 493,720 | |
| Small commercial & industrial | 61,376 |
| | 61,141 |
| Small commercial & industrial | 61,521 | | | 61,376 | |
| Large commercial & industrial | 3,418 |
| | 3,569 |
| Large commercial & industrial | 3,305 | | | 3,418 | |
| Public authorities & electric railroads | 676 |
| | 656 |
| Public authorities & electric railroads | 694 | | | 676 | |
| Total | 559,190 |
| | 555,327 |
| Total | 562,742 | | | 559,190 | |
_________
| |
(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. |
(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 Revenueincreased for the three and nine months ended September 30, 20192020 compared to the same period in 20182019 primarily due to higher electric distribution rates charged to customers that became effective in April 2019 partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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.April 2020.
Transmission Revenues. 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 increaseddecreased for the three and nine months ended September 30, 20192020 compared to the same period in 20182019, primarily due to rate increasessettlement agreement for ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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 an increaseBGS 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 and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the highest daily peak load.choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, but impact Operating revenues related to supplied electricity. Drivers of Operating revenues related to commodity, REC and ZEC procurement costs, and participation in customer choice programs are fully offset by their impact on Purchased power expense. ACE recovers electricity, REC, and ZEC procurement costs from customers without mark-up.
See Note 184 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The increase of $1 million for the three months ended September 30, 2020 and decrease of $10 million for the nine months ended September 30, 2020 compared to the same period in 2019, 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:
| | | | | | | | Three Months Ended
September 30, 2020 | | Nine Months Ended September 30, 2020 |
| | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 | | (Decrease) Increase | | Increase (Decrease) |
| | Increase (Decrease) | | Increase (Decrease) | |
| Baseline | | | | |
| Labor, other benefits, contracting and materials | $ | 2 |
| | $ | (4 | ) | Labor, other benefits, contracting and materials | $ | (2) | | | $ | 7 | |
Uncollectible accounts expense(a) | (3 | ) | | (9 | ) | |
| Pension and non-pension postretirement benefits expense | | Pension and non-pension postretirement benefits expense | — | | | (1) | |
| Storm-related costs | 1 |
| | 1 |
| Storm-related costs | 1 | | | (1) | |
| BSC and PHISCO costs | (1 | ) | | (4 | ) | BSC and PHISCO costs | (1) | | | (2) | |
| Other | 3 |
| | (4 | ) | Other | (2) | | | (6) | |
| | 2 |
| | (20 | ) | | (4) | | | (3) | |
| | | | | |
| Regulatory required programs | (1 | ) | | 11 |
| |
| Total Increase (Decrease) | $ | 1 |
| | $ | (9 | ) | |
Regulatory required programs(a) | | Regulatory required programs(a) | (5) | | | — | |
| Total decrease | | Total decrease | $ | (9) | | | $ | (3) | |
_________
| |
(a) | 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. |
The changes in Depreciation and amortization expense consisted of the following:
| | | | Three Months Ended
September 30, 2019 | | Nine Months Ended
September 30, 2019 | | Three Months Ended
September 30, 2020 | | Nine Months Ended September 30, 2020 |
| | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) | | Increase (Decrease) |
Depreciation and amortization(a) | $ | 8 |
| | $ | 19 |
| Depreciation and amortization(a) | $ | 3 | | | $ | 14 | |
Regulatory asset amortization(b) | 3 |
| | 5 |
| |
| Regulatory asset amortization | | Regulatory asset amortization | (1) | | | (2) | |
| Regulatory required programs | (6 | ) | | (17 | ) | Regulatory required programs | 3 | | | 8 | |
| Total increase | $ | 5 |
| | $ | 7 |
| Total increase | $ | 5 | | | $ | 20 | |
_________
| |
(a) | Depreciation and amortization increased primarily due to ongoing capital expenditures. |
| |
(b) | Regulatory asset amortization increased primarily due to additional regulatory assets related to rate case activity. |
Interest expense, net(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Gain on sale of assets for the nine months ended September 30, 20192020 compared to the same period in 2018 decreased primarily2019 increased due to lower outstanding debt.
Other, net for the nine months ended September 30, 2019 compared to the same periodsale of land in 2018 increased primarily due to higher income from AFUDC equity.February 2020.
Effective income tax rates were 3.1%(10.3)% and 11.6%3.1% for the three months ended September 30, 2020 and 2019, and 2018, respectively, (58.2)% and 2.2% and 13.6% for the nine months ended September 30, 20192020 and 2018,2019, respectively. The decreasechange is primarily duerelated to the accelerated amortizationsettlement agreement of certain deferredongoing transmission-related income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements.liabilities. See Note 122 — Regulatory Matters and Note 9 — 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
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 $645 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 2021borrowings from the Exelon intercompany money pool. See Note 5 - Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the sale of customer accounts receivable. Exelon Corporate, Generation, and $159 million in credit facilitiesthe Utility Registrants continued to issue commercial paper during the third quarter of 2020. See Executive Overview for project finance.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 benefit 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, the 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 1112 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.
Despite disruptions in the financial markets due to COVID-19, the Registrants have been able to fund their liquidity needs to date. As of December 31, 2019, Exelon had approximately $4.0 billion of long-term debt that matures in 2020, excluding project financings and floating rate long-term debt. Of this, as of September 30, 2020, Exelon has redeemed or refinanced approximately $3.4 billion that is maturing in 2020. The remaining amount of $0.6 billion on Exelon’s and Generation’s Consolidated Balance Sheet was redeemed on October 2, 2020. To date in 2020, the Registrants have been able to execute their expected debt issuances and have issued long-term debt of $5.3 billion, of which $4.1 billion was issued in the period of April to October of 2020. The Registrants accelerated the timing of a number of planned debt issuances resulting in the $4.1 billion issued in the period of April to October of 2020 and the Registrants have now completed their planned long-term debt issuances for the 2020 year.
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 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 137 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional 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 fund investmentsfunds 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 PSDAR to the NRC that includes the planned option for decommissioning the site. Upon 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 value, Byron may no longer meet the NRC minimum funding requirements and, as a result, the NRC 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 radiological decommissioning at Byron of up to $275 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 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 the owner(s)Generation without reimbursement from or access to the NDT funds. The ultimate costs forAccordingly, 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.
settlement agreement, decommissioning for Byron may require supplemental cash from Generation of up to $180 million, net of taxes, over a period of 10 years after permanent shutdown.
As of September 30, 2019,2020, Exelon would not be required to post a parental guarantee for TMI Unit 1 under the SAFSTOR scenario which is the planned decommissioning option as described in the TMI Unit 1 PSDAR filed by Generation with the NRC on April 5, 2019. On October 16, 2019, the NRC granted Generation's exemption request to use the TMI Unit 1 NDT funds for spent fuel management costs. An additional exemption request would be required to allow the funds to be spent on site restoration costs, which are not expected to be incurred in the near term.
Project Financing (Exelon and Generation)
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. See Note 1112 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. Refer to Note 1316 — Debt and Credit Agreements of the Exelon 20182019 Form 10-K for additional information on credit facilities.
Pension Funding Strategy (All Registrants)
Management considers various factors when making qualified 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). Beginning in 2020, Exelon will implement 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, Exelon’s estimated annual qualified pension contributions will be approximately $500 million beginning in 2020. This funding strategy does not change Exelon’s expected 2019 qualified pension contributions of approximately $300 million.
Cash Flows from Operating Activities (All Registrants)
General
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.customers and the sale of certain receivables.
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, and their ability to achieve operating cost reductions.
See Notes 4Note 3 — Regulatory Matters and 22Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 20182019 Form 10-K for additional information of regulatory and legal proceedings and proposed legislation.
The following table provides a summary of the change in cash flows from operating activities for the nine months ended September 30, 20192020 and 20182019 by Registrant:
| | | Increase (Decrease) in cash flows from operating activities | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
| (Decrease) increase in cash flows from operating activities | | (Decrease) increase in cash flows from operating activities | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Net income | $ | 241 |
| | $ | 117 |
| | $ | 21 |
| | $ | 74 |
| | $ | 19 |
| | $ | 76 |
| | $ | 43 |
| | $ | 26 |
| | $ | 11 |
| Net income | $ | (701) | | | $ | (299) | | | $ | (240) | | | $ | (93) | | | $ | 12 | | | $ | 6 | | | $ | 10 | | | $ | (25) | | | $ | 19 | |
| Adjustments to reconcile net income to cash: | | | | | | | | | | | | | | | | | | Adjustments to reconcile net income to cash: | |
| Non-cash operating activities | (399 | ) | | (293 | ) | | (35 | ) | | 12 |
| | 15 |
| | (22 | ) | | 13 |
| | (18 | ) | | (18 | ) | Non-cash operating activities | 562 | | | 264 | | | 353 | | | — | | | 25 | | | (91) | | | (84) | | | 13 | | | (9) | |
| Pension and non-pension postretirement benefit contributions | (15 | ) | | (31 | ) | | (30 | ) | | (1 | ) | | 5 |
| | 51 |
| | 1 |
| | (1 | ) | | 6 |
| Pension and non-pension postretirement benefit contributions | (203) | | | (84) | | | (74) | | | 8 | | | (29) | | | (20) | | | 2 | | | — | | | (3) | |
| Income taxes | (23 | ) | | 107 |
| | 90 |
| | 1 |
| | 5 |
| | 20 |
| | (5 | ) | | 11 |
| | 8 |
| Income taxes | (174) | | | (215) | | | (47) | | | 63 | | | 89 | | | (3) | | | 12 | | | (23) | | | (1) | |
| Changes in working capital and other noncurrent assets and liabilities | (653 | ) | | (367 | ) | | (72 | ) | | (40 | ) | | (50 | ) | | (93 | ) | | (63 | ) | | (31 | ) | | 19 |
| Changes in working capital and other noncurrent assets and liabilities | (1,415) | | | (1,564) | | | (20) | | | 119 | | | (39) | | | 48 | | | 104 | | | (5) | | | (54) | |
| Option premiums received, net | 49 |
| | 49 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
| Collateral posted, net | (476 | ) | | (520 | ) | | 53 |
| | — |
| | (6 | ) | | — |
| | — |
| | — |
| | — |
| |
| (Decrease) Increase in cash flows from operating activities | $ | (1,276 | ) | | $ | (938 | ) | | $ | 27 |
| | $ | 46 |
| | $ | (12 | ) | | $ | 32 |
| | $ | (11 | ) | | $ | (13 | ) | | $ | 26 |
| |
| Option premiums (paid) received, net | | Option premiums (paid) received, net | (144) | | | (144) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Collateral received (posted), net | | Collateral received (posted), net | 898 | | | 932 | | | (40) | | | — | | | 5 | | | — | | | — | | | — | | | — | |
| (Decrease) increase in cash flows from operating activities | | (Decrease) increase in cash flows from operating activities | $ | (1,177) | | | $ | (1,110) | | | $ | (68) | | | $ | 97 | | | $ | 63 | | | $ | (60) | | | $ | 44 | | | $ | (40) | | | $ | (48) | |
Changes in the Registrants' cash flows from operations 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, except as discussed below. In addition, significant operating cash flow impacts for the Registrants for the nine months ended September 30, 20192020 and 20182019 were as follows:
| |
• | •See Note 17 — 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. •See Note 9 — 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 5 — Accounts Receivable for additional information on the sales of customer accounts receivable.
|
| |
• | 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.
|
Cash Flows from Investing Activities (All Registrants)
The following table provides a summary of the change in cash flows from investing activities for the nine months ended September 30, 20192020 and 20182019 by Registrant:
| | | Increase (Decrease) in cash flows from investing activities | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
| Increase (decrease) in cash flows from investing activities | | Increase (decrease) in cash flows from investing activities | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Capital expenditures | $ | 238 |
| | $ | 378 |
| | $ | 127 |
| | $ | (60 | ) | | $ | (175 | ) | | $ | (18 | ) | | $ | 20 |
| | $ | 9 |
| | $ | (53 | ) | Capital expenditures | $ | (347) | | | $ | 70 | | | $ | (170) | | | $ | (149) | | | $ | 4 | | | $ | (66) | | | $ | (57) | | | $ | (33) | | | $ | 19 | |
| Proceeds from NDT fund sales, net | 180 |
| | 180 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Proceeds from NDT fund sales, net | (74) | | | (74) | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Acquisitions of assets and businesses, net | 57 |
| | 57 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
| | Proceeds from sales of assets and businesses | (73 | ) | | (73 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Proceeds from sales of assets and businesses | 29 | | | 29 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Changes in intercompany money pool | | Changes in intercompany money pool | — | | | — | | | — | | | 68 | | | — | | | — | | | (117) | | | — | | | — | |
| Collection of DPP | | Collection of DPP | 2,518 | | | 2,518 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Other investing activities | (8 | ) | | (1 | ) | | 3 |
| | 1 |
| | (4 | ) | | 1 |
| | (1 | ) | | — |
| | 1 |
| Other investing activities | (23) | | | 11 | | | (25) | | | (3) | | | (4) | | | — | | | (5) | | | (4) | | | 5 | |
| Increase (Decrease) in cash flows from investing activities | $ | 394 |
| | $ | 541 |
| | $ | 130 |
| | $ | (59 | ) | | $ | (179 | ) | | $ | (17 | ) | | $ | 19 |
| | $ | 9 |
| | $ | (52 | ) | |
| Increase (decrease) in cash flows from investing activities | | Increase (decrease) in cash flows from investing activities | $ | 2,103 | | | $ | 2,554 | | | $ | (195) | | | $ | (84) | | | $ | — | | | $ | (66) | | | $ | (179) | | | $ | (37) | | | $ | 24 | |
Significant investing cash flow impacts for the Registrants for nine months ended September 30, 20192020 and 20182019 were as follows:
| |
• | •Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer below for additional information on projected capital expenditure spending. •Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer to Liquidity and Capital Resources of the Exelon 2018 Form 10-K for additional information on projected capital expenditure spending. |
| |
• | During the nine months ended September 30, 2018, Exelon and Generation had proceeds of $79 million relating to the sale of its interest in an electrical contracting business.
|
Capital Expenditure Spending
As of September 30, 2019, there have been no material changes to2020, the Registrants’ projectedmost recent estimates of capital expenditures for plant additions and improvements for 2020 are as disclosedfollows:
| | | | | | | | | | | | | | |
| (In millions) | Transmission | Distribution | Gas | Total |
| Exelon | N/A | N/A | N/A | $ | 8,075 | |
| Generation | N/A | N/A | N/A | 1,500 | |
| ComEd | 425 | | 1,900 | | N/A | 2,325 | |
| PECO | 100 | | 800 | | 300 | | 1,200 | |
| BGE | 275 | | 550 | | 475 | | 1,300 | |
| PHI | 425 | | 1,100 | | 100 | | 1,625 | |
| Pepco | 150 | | 650 | | N/A | 800 | |
| DPL | 100 | | 250 | | 100 | | 450 | |
| ACE | 175 | | 200 | | N/A | 375 | |
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in Liquidityeconomic conditions and Capital Resourcesother factors.
Cash Flows from Financing Activities (All Registrants)
The following table provides a summary of the change in cash flows from financing activities for the nine months ended September 30, 20192020 and 20182019 by Registrant:
| | | Increase (Decrease) in cash flows from financing activities | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
| Increase (decrease) in cash flows from financing activities | | Increase (decrease) in cash flows from financing activities | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
| Changes in short-term borrowings, net | $ | 398 |
| | $ | — |
| | $ | 387 |
| | $ | — |
| | $ | 42 |
| | $ | (31 | ) | | $ | (66 | ) | | $ | 273 |
| | $ | 37 |
| Changes in short-term borrowings, net | $ | (494) | | | $ | 220 | | | $ | (376) | | | $ | — | | | $ | (41) | | | $ | (161) | | | $ | (54) | | | $ | (113) | | | $ | 6 | |
| Long-term debt, net | (252 | ) | | (69 | ) | | (410 | ) | | 125 |
| | 100 |
| | 13 |
| | 50 |
| | (196 | ) | | (116 | ) | Long-term debt, net | 666 | | | (1,053) | | | 400 | | | 25 | | | — | | | 202 | | | 156 | | | 99 | | | (52) | |
| Changes in intercompany money pool | — |
| | (46 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Changes in intercompany money pool | — | | | 100 | | | — | | | — | | | — | | | (1) | | | — | | | — | | | 117 | |
| | Dividends paid on common stock | (56 | ) | | — |
| | (35 | ) | | 32 |
| | (12 | ) | | — |
| | (45 | ) | | (47 | ) | | (54 | ) | Dividends paid on common stock | (64) | | | — | | | 6 | | | 13 | | | (17) | | | — | | | (1) | | | 6 | | | (11) | |
| Distributions to member | — |
| | 14 |
| | — |
| | — |
| | — |
| | (197 | ) | | — |
| | — |
| | — |
| Distributions to member | — | | | (732) | | | — | | | — | | | — | | | (22) | | | — | | | — | | | — | |
| Contributions from parent/member | — |
| | (54 | ) | | (200 | ) | | 103 |
| | 86 |
| | 46 |
| | 44 |
| | (150 | ) | | 155 |
| Contributions from parent/member | — | | | 64 | | | 301 | | | 74 | | | 180 | | | 210 | | | 133 | | | 112 | | | (38) | |
| | Other financing activities | 58 |
| | 9 |
| | 6 |
| | 16 |
| | (5 | ) | | 1 |
| | 1 |
| | 3 |
| | (1 | ) | Other financing activities | (73) | | | (11) | | | (4) | | | 2 | | | (1) | | | (5) | | | (3) | | | (1) | | | — | |
| Increase (Decrease) in cash flows from financing activities | $ | 148 |
| | $ | (146 | ) | | $ | (252 | ) | | $ | 276 |
| | $ | 211 |
| | $ | (168 | ) | | $ | (16 | ) | | $ | (117 | ) | | $ | 21 |
| |
| Increase (decrease) in cash flows from financing activities | | Increase (decrease) in cash flows from financing activities | $ | 35 | | | $ | (1,412) | | | $ | 327 | | | $ | 114 | | | $ | 121 | | | $ | 223 | | | $ | 231 | | | $ | 103 | | | $ | 22 | |
Significant financing cash flow impacts for the Registrants for the nine months ended September 30, 20192020 and 20182019 were as follows:
| |
• | Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 90 days. Refer to 11•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to 12 — Debt and Credit Agreements of the 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 12 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on debt issuances. Refer to debt redemptions tables below for more information. •Changes in intercompany 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 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2019 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared. •For the nine months ended September 30, 2020, other financing activities primarily consists of debt issuance costs. See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances. |
| |
• | Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to 11 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on debt issuances. Refer to debt redemptions tables below for more information.
|
| |
• | Changes in intercompany 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 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2018 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
|
Debt
See Note 1112 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.
During the nine months ended September 30, 2019,2020, the following long-term debt was retired and/or redeemed:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Company(a) | | Type | | Interest Rate | | Maturity | | Amount |
| Exelon | | Notes | | 2.85 | % | | June 15, 2020 | | $ | 900 | |
| Exelon | | Long-Term Software License Agreement | | 3.95 | % | | May 1, 2024 | | 24 | |
| Generation | | Senior Notes | | 2.95 | % | | January 15, 2020 | | 1,000 | |
| Generation | | Senior Notes | | 4.00 | % | | October 1, 2020 | | 550 | |
| Generation | | Tax-Exempt Bonds | | 2.50% - 2.70% | | December 1, 2025 - June 1, 2036 | | 412 | |
| Generation | | ExGen Renewables IV Nonrecourse Debt(b) | | 3mL +3% | | November 30, 2024 | | 87 | |
| Generation | | Continental Wind Nonrecourse Debt(b) | | 6.00 | % | | February 28, 2033 | | 33 | |
| Generation | | Antelope Valley DOE Nonrecourse Debt(b) | | 2.29% - 3.56% | | January 5, 2037 | | 13 | |
| Generation | | Renewable Power Generation Nonrecourse Debt(b) | | 4.11 | % | | March 31, 2035 | | 9 | |
| Generation | | Energy Efficiency Project Financing | | 3.71 | % | | December 31, 2020 | | 4 | |
| Generation | | NUKEM | | 3.15 | % | | September 30, 2020 | | 3 | |
| Generation | | SolGen Nonrecourse Debt | | 3.93 | % | | September 30, 2036 | | 2 | |
| Generation | | Energy Efficiency Project Financing | | 4.12 | % | | November 30, 2020 | | 1 | |
| ComEd | | First Mortgage Bonds | | 4.00 | % | | August 1, 2020 | | 500 | |
| DPL | | Tax-Exempt Bonds | | 5.40 | % | | February 1, 2031 | | 78 | |
| ACE | | Tax-Exempt First Mortgage Bonds | | 4.88 | % | | June 1, 2029 | | 23 | |
| ACE | | Transition Bonds | | 5.55 | % | | October 20, 2023 | | 14 | |
|
| | | | | | | | | | | |
Company (a) | | Type | | Interest Rate | | Maturity | | Amount |
| Exelon | | Oracle Annual Lease Payment | | 3.95 | % | | May 1, 2024 | | $ | 18 |
|
| Generation | | Antelope Valley DOE Nonrecourse Debt | | 2.33% - 3.56% |
| | January 5, 2037 | | 12 |
|
| Generation | | Kennett Square Capital Lease | | 7.83 | % | | September 20, 2020 | | 3 |
|
| Generation | | Continental Wind Nonrecourse Debt | | 6.00 | % | | February 28, 2033 | | 32 |
|
| Generation | | Pollution control notes | | 2.50 | % | | March 1, 2019 | | 23 |
|
| Generation | | Renewable Power Generation Nonrecourse Debt | | 4.11 | % | | March 31, 2035 | | 10 |
|
| Generation | | Energy Efficiency Project Financing | | 3.46 | % | | April 30, 2019 | | 39 |
|
| Generation | | ExGen Renewables IV Nonrecourse debt | | 3mL +3% |
| | November 30, 2024 | | 38 |
|
| Generation | | Hannie Mae, LLC Defense Financing | | 4.12 | % | | November 30, 2019 | | 1 |
|
| Generation | | Energy Efficiency Project Financing | | 3.72 | % | | July 31, 2019 | | 25 |
|
| Generation | | Nuclear fuel procurement contracts | | 3.15 | % | | September 30, 2020 | | 36 |
|
| Generation | | SolGen Nonrecourse Debt | | 3.93 | % | | September 30, 2036 | | 2 |
|
| Generation | | Energy Efficiency Project Financing | | 4.17 | % | | August 31, 2019 | | 1 |
|
| Generation | | Energy Efficiency Project Financing | | 3.53 | % | | March 31, 2020 | | 1 |
|
| Generation | | Energy Efficiency Project Financing | | 4.26 | % | | September 30, 2019 | | 1 |
|
| ComEd | | First Mortgage Bonds | | 2.15 | % | | January 15, 2019 | | 300 |
|
| Pepco | | Unsecured Tax-Exempt Bonds | | 6.20 | % | | September 1, 2022 | | 110 |
|
| ACE | | Transition Bonds | | 5.55 | % | | October 20, 2023 | | 13 |
|
| |
(a) | On October 1, 2019, Generation redeemed $600 million of 5.20% 2009 Senior Notes due to maturity. |
Antelope Valley’s nonrecourse(a)On October 2, 2020, Generation redeemed $550 million of 5.15% senior notes due December 1, 2020. The senior notes are legacy Constellation mirror debt of approximately $495 million was reclassified as current in Exelon’sthat were previously held at Exelon and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of September 30, 2019 as a resultGeneration. As part of the PG&E bankruptcy filing on January 29, 2019. 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 1112 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.information of nonrecourse debt.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 20192020 and for the thirdfourth quarter of 20192020 were as follows:
|
| | | | | | | | | | |
| Period | | Declaration Date | | Shareholder of Record Date | | Dividend Payable Date | | Cash per Share(a) |
| First Quarter 2019 | | February 5, 2019 | | February 20, 2019 | | March 8, 2019 | | $ | 0.3625 |
|
| Second Quarter 2019 | | April 30, 2019 | | May 15, 2019 | | June 10, 2019 | | $ | 0.3625 |
|
| Third Quarter 2019 | | July 30, 2019 | | August 15, 2019 | | September 10, 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 through 2020.Record Date | | Dividend Payable Date | | Cash per Share(a) |
| First Quarter 2020 | | January 28, 2020 | | February 20, 2020 | | March 10, 2020 | | $ | 0.3825 | |
| Second Quarter 2020 | | April 28, 2020 | | May 15, 2020 | | June 10, 2020 | | $ | 0.3825 | |
| Third Quarter 2020 | | July 28, 2020 | | August 14, 2020 | | September 10, 2020 | | $ | 0.3825 | |
| | | | | | | | |
| Fourth Quarter 2020 | | November 2, 2020 | | November 16, 2020 | | December 10, 2020 | | $ | 0.3825 | |
| | | | | | | | |
| | | | | | | | |
Other
For_________
(a)Exelon's Board of Directors approved an updated dividend policy providing an increase of 5% each year for the nine months ended September 30, 2019, other financing activities primarily consist of debt issuance costs. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.
period covering 2018 through 2020.
Credit Matters (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 $9.8$10.6 billion in aggregate total commitments of which $8.5 billion was available to support additional commercial paper as of September 30, 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 market markets and had availability under their revolving credit facilitiesduring the third quarter of 20192020 to fund their short-term liquidity needs, when necessary.needs. 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 of the Exelon 20182019 Form 10-K 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 September 30, 2019,2020, it would have been required to provide incremental collateral of $1.5$1.3 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 $4.2$4.9 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 September 30, 20192020 and available credit facility capacity prior to any incremental collateral at September 30, 2019:2020:
| | | | | | | | | | 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 | $ | 10 |
| | $ | — |
| | $ | 995 |
| ComEd | $ | 12 | | | $ | — | | | $ | 857 | |
| PECO | — |
| | 28 |
| | 600 |
| PECO | — | | | 22 | | | 600 | |
| BGE | 12 |
| | 26 |
| | 594 |
| BGE | 11 | | | 31 | | | 600 | |
| | Pepco | 10 |
| | — |
| | 290 |
| Pepco | 11 | | | — | | | 299 | |
| DPL | 6 |
| | 11 |
| | 300 |
| DPL | 4 | | | 10 | | | 300 | |
| ACE | — |
| | — |
| | 300 |
| ACE | — | | | — | | | 300 | |
_________
| |
(a) | Represents incremental collateral related to natural gas procurementRepresents 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 11Note 12 — Debt and Credit Agreements and Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ short-term borrowing activity.
See Note 1316 — Debt and Credit Agreements and Note 22 — Commitments and Contingencies of the Exelon 20182019 Form 10-K for additional information on the Registrants’ credit facilities.
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 1011 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The credit ratings for Exelon Corporate, Generation, PECO, BGE, PHI, Pepco, DPL, and ACE did not change for the nine months ended September 30, 2020. 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 September 30, 2019,2020, are presented in the following table:
| | | | | | | | | | | | | | | | | | | | |
| Exelon Intercompany Money Pool | | During the Three Months Ended September 30, 2020 | | As of September 30, 2020 |
| Contributed (Borrowed) | | Maximum
Contributed | | Maximum
Borrowed | | Contributed
(Borrowed) |
| Exelon Corporate | | $ | 871 | | | $ | — | | | $ | 333 | |
| Generation | | — | | | (527) | | | — | |
| PECO | | 35 | | | — | | | — | |
| BSC | | — | | | (494) | | | (372) | |
| PHI Corporate | | — | | | (22) | | | (21) | |
| PCI | | 60 | | | — | | | 60 | |
|
| | | | | | | | | | | | |
| Exelon Intercompany Money Pool | | During the Three Months Ended September 30, 2019 | | As of September 30, 2019 |
| Contributed (Borrowed) | | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) |
| Exelon Corporate | | $ | 260 |
| | $ | — |
| | $ | 206 |
|
| Generation | | 212 |
| | — |
| | — |
|
| PECO | | 7 |
| | (85 | ) | | — |
|
| BSC | | — |
| | (338 | ) | | (251 | ) |
| PHI Corporate | | — |
| | (10 | ) | | (10 | ) |
| PCI | | 55 |
| | — |
| | 55 |
|
| | | PHI Intercompany Money Pool | | During the Three Months Ended September 30, 2019 | | As of September 30, 2019 | PHI Intercompany Money Pool | | During the Three Months Ended September 30, 2020 | | As of September 30, 2020 |
| Contributed (Borrowed) | | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) | Contributed (Borrowed) | | Maximum
Contributed | | Maximum
Borrowed | | Contributed
(Borrowed) |
| | Pepco | | 63 |
| | — |
| | — |
| Pepco | | $ | 123 | | | $ | (57) | | | $ | 117 | |
| DPL | | — |
| | (46 | ) | | — |
| DPL | | 61 | | | — | | | — | |
| ACE | | — |
| | (29 | ) | | — |
| ACE | | — | | | (129) | | | (117) | |
| PHISCO | | 2 |
| | — |
| | 2 |
| |
|
Shelf Registration Statements
Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 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 ACE are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
| | | | | | | | | | | | | | | | | As of September 30, 2020 |
| | | As of September 30, 2019 | | Short-term Financing Authority(a) | | Remaining Long-term Financing Authority(a) |
| | | Short-term Financing Authority(a)(b) | | Remaining Long-term Financing Authority(a) | Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount |
| Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount | |
ComEd(c) | | FERC | | December 31, 2019 | | $ | 2,500 |
| | ICC | | August 1, 2021 | | $ | 693 |
| |
| ComEd | | ComEd | | FERC | | December 31, 2021 | | $ | 2,500 | | | ICC | | February 1, 2023 | | $ | 893 | |
| PECO | | FERC | | December 31, 2019 | | 1,500 |
| | PAPUC | | December 31, 2021 | | 1,575 |
| PECO | | FERC | | December 31, 2021 | | 1,500 | | | PAPUC | | December 31, 2021 | | 1,225 | |
| BGE | | FERC | | December 31, 2019 | | 700 |
| | MDPSC | | N/A | | — |
| BGE | | FERC | | December 31, 2021 | | 700 | | | MDPSC | | N/A | | 1,100 | |
| Pepco | | FERC | | December 31, 2019 | | 500 |
| | MDPSC / DCPSC | | December 31, 2020 | | 141 |
| 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 | | 375 | |
| ACE | | NJBPU | | December 31, 2019 | | 350 |
| | NJBPU | | December 31, 2020 | | 200 |
| |
ACE(b) | | ACE(b) | | NJBPU | | December 31, 2021 | | 350 | | | NJBPU | | December 31, 2020 | | 77 | |
_________
| |
(a) | (a)Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority. |
| |
(b) | On October 15, 2019, ComEd, PECO, BGE, Pepco and DPL filed applications with FERC and on September 12, 2019, ACE filed an application with NJBPU for renewal of their short-term financing authority through December 31, 2021. ComEd, PECO, BGE, Pepco, DPL and ACE expect approval of the applications before the end of the year. |
| |
(c) | ComEd had $693 million available in new money long-term debt financing authority from the ICC as of September 30, 2019 and has an expiration date of August 1, 2021. |
(b)On August 12, 2020, ACE filed an application for $600 million in new long-term debt financing authority from the NJBPU and expects approval before the end of the year.
Contractual Obligations and Off-Balance Sheet Arrangements
Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 2218 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 20182019 Form 10-K.
Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd and PECO have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements in the Exelon 2019 Form 10-K for additional information.
For an in-depth discussion of the Registrants' contractual obligations and off-balance sheet arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet Arrangements” in the Exelon 20182019 Form 10-K. In addition, see discussion of off-balance sheet arrangement discussed below.
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 5 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
Item 3. 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. The following discussion serves as an update to ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of Exelon’s 20182019 Annual Report on Form 10-K incorporated herein by reference.
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 20192020 through 2021.2022.
As of September 30, 2019,2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 96%-99%, 84%-87%97%-100% and 54%-57%87%-90% for 2019, 2020 and 2021, respectively. 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 September 30, 20192020 market conditions and hedged position would be immaterial for 2019, and decreasesa decrease in pre-tax net income of approximately $88$14 million and $399$99 million, respectively, for 2020 and 2021. See Note 1011 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Fuel Procurement
Approximately 63%60% of Generation’s uranium concentrate requirements from 20192020 through 20232024 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
There have been no significant changes or additions to the Utility Registrants exposures to commodity price risk that were described in ITEM 1A. RISK FACTORS of Exelon’s 20182019 Annual Report on Form 10-K. See Note 1011 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding commodity price risk exposure.
Trading and Non-Trading Marketing Activities
The following table detailing Exelon’s, Generation’s, and ComEd’s trading and non-trading marketing activities isare 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, 20182019 to September 30, 2019.2020. 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 1011 — 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 September 30, 20192020 and December 31, 2018.2019.
|
| | | | | | | | | | | |
| | Exelon | | Generation | | ComEd |
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 results of operations | (273 | ) | | (273 | ) | | — |
|
| Reclassification to realized of contracts recorded in results of operations | 215 |
| | 215 |
| | — |
|
Changes in fair value — recorded through regulatory assets and liabilities(b) | (31 | ) | | — |
| | (31 | ) |
| Changes in allocated collateral | 364 |
| | 364 |
| | — |
|
| Net option premium paid/(received) | (13 | ) | | (13 | ) | | — |
|
| Option premium amortization | (21 | ) | | (21 | ) | | — |
|
Upfront payments and amortizations(c) | (73 | ) | | (73 | ) | | — |
|
Total mark-to-market energy contract net assets (liabilities) at September 30, 2019(a) | $ | 467 |
| | $ | 747 |
| | $ | (280 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | | | |
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 results of operations | 14 | | | 14 | | | — | | | | | |
| Reclassification to realized at settlement of contracts recorded in results of operations | 436 | | | 436 | | | — | | | | | |
| | | | | | | | | |
Changes in fair value — recorded through regulatory assets(b) | (3) | | | — | | | (3) | | | | | |
| Changes in allocated collateral | (678) | | | (678) | | | — | | | | | |
| Net option premium paid | 131 | | | 131 | | | — | | | | | |
| Option premium amortization | (79) | | | (79) | | | — | | | | | |
Upfront payments and amortizations(c) | (80) | | | (80) | | | — | | | | | |
Total mark-to-market energy contract net assets (liabilities) at September 30, 2020(a) | $ | 308 | | | $ | 612 | | | $ | (304) | | | | | |
_________
| |
(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 September 30, 2019, ComEd recorded a regulatory liability of $280 million related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the nine months ended September 30, 2019, ComEd recorded $31 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. |
| |
(c) | Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations |
(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 September 30, 2020, ComEd recorded a regulatory asset of $304 million related to its mark-to-market derivative liabilities with unaffiliated suppliers. For the nine months ended September 30, 2020, ComEd recorded $26 million of decreases in fair value and an increase for realized losses due to settlements of $23 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.
(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 913 — 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 | | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 and Beyond | |
Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | | Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | |
| Actively quoted prices (Level 1) | $ | (22 | ) | | $ | (105 | ) | | $ | (25 | ) | | $ | (13 | ) | | $ | 9 |
| | $ | 9 |
| | $ | (147 | ) | Actively quoted prices (Level 1) | $ | 4 | | | $ | 69 | | | $ | 13 | | | $ | 11 | | | $ | 11 | | | $ | 18 | | | $ | 126 | |
| Prices provided by external sources (Level 2) | 76 |
| | (1 | ) | | 47 |
| | (10 | ) | | — |
| | — |
| | 112 |
| Prices provided by external sources (Level 2) | 41 | | | 60 | | | 34 | | | 18 | | | (1) | | | 1 | | | 153 | |
Prices based on model or other valuation methods (Level 3)(c) | 65 |
| | 442 |
| | 116 |
| | 33 |
| | (6 | ) | | (148 | ) | | 502 |
| Prices based on model or other valuation methods (Level 3)(c) | 17 | | | 139 | | | 36 | | | 14 | | | (11) | | | (166) | | | 29 | |
| Total | $ | 119 |
| | $ | 336 |
| | $ | 138 |
| | $ | 10 |
| | $ | 3 |
| | $ | (139 | ) | | $ | 467 |
| Total | $ | 62 | | | $ | 268 | | | $ | 83 | | | $ | 43 | | | $ | (1) | | | $ | (147) | | | $ | 308 | |
_________
| |
(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 $721 million at September 30, 2019. |
| |
(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 $251 million at September 30, 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 | | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 and Beyond | |
Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | | Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | |
| Actively quoted prices (Level 1) | $ | (22 | ) | | $ | (105 | ) | | $ | (25 | ) | | $ | (13 | ) | | $ | 9 |
| | $ | 9 |
| | $ | (147 | ) | Actively quoted prices (Level 1) | $ | 4 | | | $ | 69 | | | $ | 13 | | | $ | 11 | | | $ | 11 | | | $ | 18 | | | $ | 126 | |
| Prices provided by external sources (Level 2) | 76 |
| | (1 | ) | | 47 |
| | (10 | ) | | — |
| | — |
| | 112 |
| Prices provided by external sources (Level 2) | 41 | | | 60 | | | 34 | | | 18 | | | (1) | | | 1 | | | 153 | |
| Prices based on model or other valuation methods (Level 3) | 75 |
| | 469 |
| | 143 |
| | 60 |
| | 21 |
| | 14 |
| | 782 |
| Prices based on model or other valuation methods (Level 3) | 28 | | | 167 | | | 64 | | | 42 | | | 16 | | | 16 | | | 333 | |
| Total | $ | 129 |
| | $ | 363 |
| | $ | 165 |
| | $ | 37 |
| | $ | 30 |
| | $ | 23 |
| | $ | 747 |
| Total | $ | 73 | | | $ | 296 | | | $ | 111 | | | $ | 71 | | | $ | 26 | | | $ | 35 | | | $ | 612 | |
_________
| |
(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 $721 million at September 30, 2019. |
(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 $251 million at September 30, 2020.
ComEd
| | | | Maturities Within | | Total Fair
Value | | Maturities Within | | Total Fair
Value |
| | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and Beyond | | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 and Beyond | |
Commodity derivative contracts(a): | | | | | | | | | | | | | | Commodity derivative contracts(a): | | | | | | | | | | | | | |
| Prices based on model or other valuation methods (Level 3) | $ | (10 | ) | | $ | (27 | ) | | $ | (27 | ) | | $ | (27 | ) | | $ | (27 | ) | | $ | (162 | ) | | $ | (280 | ) | |
Prices based on model or other valuation methods (Level 3)(a) | | Prices based on model or other valuation methods (Level 3)(a) | $ | (11) | | | $ | (28) | | | $ | (28) | | | $ | (28) | | | $ | (27) | | | $ | (182) | | | $ | (304) | |
_________
| |
(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 (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 1011 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for detailed discussion of credit 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 September 30, 2019.2020. 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 tables 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 $68 million, $30 million, $32 million, $39 million, $15 million and $8 million as of September 30, 2019, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Rating as of September 30, 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 | | $ | 638 | | | $ | 27 | | | $ | 611 | | | — | | | $ | — | |
| Non-investment grade | | 4 | | | — | | | 4 | | | | | |
| No external ratings | | | | | | | | | | |
| Internally rated — investment grade | | 168 | | | 1 | | | 167 | | | | | |
| Internally rated — non-investment grade | | 110 | | | 29 | | | 81 | | | | | |
| Total | | $ | 920 | | | $ | 57 | | | $ | 863 | | | — | | | $ | — | |
| | | | | | | | | | | | | | Maturity of Credit Risk Exposure |
| Rating as of September 30, 2019 | | 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 September 30, 2020 | | Rating as of September 30, 2020 | | Less than
2 Years | | 2-5 Years | | Exposure
Greater than
5 Years | | Total Exposure
Before Credit
Collateral |
| Investment grade | | $ | 693 |
| | $ | 10 |
| | $ | 683 |
| | $ | — |
| | $ | — |
| Investment grade | | $ | 568 | | | $ | 51 | | | $ | 19 | | | $ | 638 | |
| Non-investment grade | | 74 |
| | 38 |
| | 36 |
| |
|
| |
|
| Non-investment grade | | 4 | | | — | | | — | | | 4 | |
| No external ratings | | | | | | | | | | | No external ratings | |
| Internally rated — investment grade | | 297 |
| | 1 |
| | 296 |
| |
|
| |
|
| Internally rated — investment grade | | 123 | | | 27 | | | 18 | | | 168 | |
| Internally rated — non-investment grade | | 175 |
| | 24 |
| | 151 |
| |
|
| |
|
| Internally rated — non-investment grade | | 89 | | | 9 | | | 12 | | | 110 | |
| Total | | $ | 1,239 |
| | $ | 73 |
| | $ | 1,166 |
| | $ | — |
| | $ | — |
| Total | | $ | 784 | | | $ | 87 | | | $ | 49 | | | $ | 920 | |
|
| | | | | | | | | | | | | | | | |
| | | Maturity of Credit Risk Exposure |
| Rating as of September 30, 2019 | | Less than 2 Years | | 2-5 Years | | Exposure Greater than 5 Years | | Total Exposure Before Credit Collateral |
| Investment grade | | $ | 649 |
| | $ | 38 |
| | $ | 6 |
| | $ | 693 |
|
| Non-investment grade | | 76 |
| | (2 | ) | | — |
| | 74 |
|
| No external ratings | | | | | | | | |
| Internally rated — investment grade | | 234 |
| | 35 |
| | 28 |
| | 297 |
|
| Internally rated — non-investment grade | | 148 |
| | 16 |
| | 11 |
| | 175 |
|
| Total | | $ | 1,107 |
| | $ | 87 |
| | $ | 45 |
| | $ | 1,239 |
|
|
| | | | |
| Net Credit Exposure by Type of Counterparty | | As of
September 30, 2019 |
| Financial institutions | | $ | 1 |
|
| Investor-owned utilities, marketers, power producers | | 875 |
|
| Energy cooperatives and municipalities | | 255 |
|
| Other | | 35 |
|
| Total | | $ | 1,166 |
|
_________
| | | | | | | | |
(a)Net Credit Exposure by Type of Counterparty | | As of September 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $18 million of cash2020 |
| Financial institutions | | $ | 26 | |
| Investor-owned utilities, marketers, power producers | | 650 | |
Energy cooperatives and $55 million of letters of credit.municipalities | | 142 | |
| Other | | 45 | |
| Total | | $ | 863 | |
_________
(a)As of September 30, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $26 million of letters of credit.
The Utility Registrants
There have been no significant changes or additions to the Utility Registrants exposures to credit risk that are described in ITEM 1A. RISK FACTORS of Exelon’s 20182019 Annual Report on Form 10-K.
See Note 1011 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding credit exposure to suppliers.
Credit-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 1011 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements. See Note 1614 — 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 Note 1316 — Debt and Credit Agreements of the ExelonExelon’s 2019 Annual Report on Form 10-K for additional information.
Utility Registrants
As of September 30, 2019,2020, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 1011 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Interest Rate and Foreign Exchange Risk (Exelon and Generation)
Exelon and Generation use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon and Generation may also utilize interest rate swaps to manage their interest rate exposure. A hypothetical 50 basis pointpoints increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper)commercial paper) and fixed-to-floating swaps would result in approximately a $4 million decrease in Exelon pre-tax income for the nine months ended September 30, 2019.2020. 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 1011 — 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 September 30, 2019,2020, 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 $570$754 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 2. 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.
Item 4. Controls and Procedures
During the third quarter of 2019,2020, each of Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE'sthe Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in its periodic reports that it files with the SEC. These
disclosure controls and procedures have been designed by allthe Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to Exelon’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 September 30, 2019,2020, the principal executive officer and principal financial officer of each of Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACEthe Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. AllThe Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There have beenwere no changes in internal control over financial reporting that occurred during the third quarter of 20192020 that have materially affected, or are reasonably likely to materially affect, any of Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s and ACE’sthe Registrants' internal control over financial reporting.reporting, including no changes resulting from COVID-19. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview for additional information on COVID-19.
PART II — OTHER INFORMATION
Item 1. Legal Proceedings
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 (a) ITEM 3. LEGAL PROCEEDINGS of Exelon’s 20182019 Form 10-K and (b) Notes 62 — Regulatory Matters and 1614 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.
Item 1A. Risk Factors
Risks Related to Exelon
At September 30, 2019,2020, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 20182019 Form 10-K in ITEM 1A. RISK FACTORS.FACTORS, except for the following risk factors, which were added.
Our Results Could be Negatively Affected by the Impacts of COVID-19 (All Registrants).
The Registrants have taken steps to mitigate the potential risks posed by COVID-19. This 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 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 at this time. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview for additional information on COVID-19.
Exelon and ComEd have received requests for information related to an SEC investigation into their lobbying activities. The outcome of the investigation 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 criminal or 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 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report.
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 ends 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, 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; (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 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report.
Item 4. Mine Safety Disclosures
All Registrants
Not applicable to the Registrants.
Item 5. Other Information
Generation - Second Amended and Restated Operating AgreementAll Registrants
On October 30, 2019, Exelon, as sole memberNone.
Item 6. Exhibits
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 |
|
|
| |
Exhibit
No.
101.INS | Description |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
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. |
| |
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document. |
| |
| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document. |
| |
| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document.
|
| |
| 101.LAB | Inline XBRL Taxonomy Extension LabelLabels Linkbase Document. |
| |
| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document.
|
| |
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
|
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 20192020 filed by the following officers for the following companies:
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 20192020 filed by the following officers for the following companies:
SIGNATURES
Pursuant to requirements 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.
EXELON CORPORATION
|
| | | | | | | |
| /s/ CHRISTOPHER M. CRANE | | /s/ JOSEPH NIGRO |
| Christopher M. Crane | | Joseph Nigro |
President and Chief Executive Officer
(Principal Executive Officer) and Director
| | Senior Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
|
| | |
| /s/ FABIAN E. SOUZA | | |
| Fabian E. Souza | | |
Senior Vice President and Corporate Controller
(Principal Accounting Officer)
| | |
October 31, 2019November 3, 2020
Pursuant to requirements 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.
EXELON GENERATION COMPANY, LLC
|
| | | | | | | |
/s/ KENNETH W. CORNEWCHRISTOPHER M. CRANE | | /s/ BRYAN P. WRIGHT |
Kenneth W. CornewChristopher M. Crane | | Bryan P. Wright |
President and ChiefPrincipal Executive Officer
(Principal Executive Officer)
| | Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
|
| | |
| /s/ MATTHEW N. BAUER | | |
| Matthew N. Bauer | | |
Vice President and Controller
(Principal Accounting Officer)
| | |
October 31, 2019November 3, 2020
Pursuant to requirements 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.
COMMONWEALTH EDISON COMPANY
|
| | | | | | | |
| /s/ JOSEPH DOMINGUEZ | | /s/ JEANNE M. JONES |
| Joseph Dominguez | | Jeanne M. Jones |
Chief Executive Officer
(Principal Executive Officer)
| | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
|
| | |
/s/ GERALDSTEVEN J. KOZELCICHOCKI | | |
GeraldSteven J. KozelCichocki | | |
Vice President and Controller
Director, Accounting
(Principal Accounting Officer) | | |
November 3, 2020
Pursuant to requirements 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.
PECO ENERGY COMPANY
|
| | | | | | | |
| /s/ MICHAEL A. INNOCENZO | | /s/ ROBERT J. STEFANI |
| Michael A. Innocenzo | | Robert J. Stefani |
President and Chief Executive Officer
(Principal Executive Officer)
| | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
|
| | |
/s/ SCOTT A. BAILEYCAROLINE FULGINITI | | |
Scott A. BaileyCaroline Fulginiti | | |
Vice President and Controller
Director, Accounting
(Principal Accounting Officer) | | |
November 3, 2020
October 31, 2019
Pursuant to requirements 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.
BALTIMORE GAS AND ELECTRIC COMPANY
|
| | | | | | | |
/s/ CALVIN G. BUTLER, JR.CARIM V. KHOUZAMI | | /s/ DAVID M. VAHOS |
Calvin G. Butler, Jr.Carim V. Khouzami | | David M. Vahos |
Chief Executive Officer
(Principal Executive Officer)
| | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
|
| | |
/s/ ANDREW W. HOLMESJASON T. JONES | | |
Andrew W. HolmesJason T. Jones | | |
Vice President and Controller
Director, Accounting
(Principal Accounting Officer) | | |
November 3, 2020
October 31, 2019
Pursuant to requirements 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.
PEPCO HOLDINGS LLC
|
| | | | | | | |
| /s/ DAVID M. VELAZQUEZ | | /s/ PHILLIP S. BARNETT |
| David M. Velazquez | | Phillip S. Barnett |
President and Chief Executive Officer
(Principal Executive Officer)
| | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
|
| | |
/s/ ROBERT M. AIKENJULIE E. GIESE | | |
Robert M. AikenJulie E. Giese | | |
Vice President and Controller
Director, Accounting
(Principal Accounting Officer) | | |
November 3, 2020
October 31, 2019
Pursuant to requirements 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.
POTOMAC ELECTRIC POWER COMPANY
|
| | | | | | | |
| /s/ DAVID M. VELAZQUEZ | | /s/ PHILLIP S. BARNETT |
| David M. Velazquez | | Phillip S. Barnett |
President and Chief Executive Officer
(Principal Executive Officer) | | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
|
| | |
/s/ ROBERT M. AIKENJULIE E. GIESE | | |
Robert M. AikenJulie E. Giese | | |
Vice President and ControllerDirector, Accounting
(Principal Accounting Officer) | | |
November 3, 2020
October 31, 2019
Pursuant to requirements 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.
DELMARVA POWER & LIGHT COMPANY
|
| | | | | | | |
| /s/ DAVID M. VELAZQUEZ | | /s/ PHILLIP S. BARNETT |
| David M. Velazquez | | Phillip S. Barnett |
President and Chief Executive Officer
(Principal Executive Officer) | | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
|
| | |
/s/ ROBERT M. AIKENJULIE E. GIESE | | |
Robert M. AikenJulie E. Giese | | |
Vice President and ControllerDirector, Accounting
(Principal Accounting Officer) | | |
November 3, 2020
October 31, 2019
Pursuant to requirements 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.
ATLANTIC CITY ELECTRIC COMPANY
|
| | | | | | | |
| /s/ DAVID M. VELAZQUEZ | | /s/ PHILLIP S. BARNETT |
| David M. Velazquez | | Phillip S. Barnett |
President and Chief Executive Officer
(Principal Executive Officer) | | Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
|
| | |
/s/ ROBERT M. AIKENJULIE E. GIESE | | |
Robert M. AikenJulie E. Giese | | |
Vice President and ControllerDirector, Accounting
(Principal Accounting Officer) | | |
November 3, 2020