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, 2016March 31, 2017
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 | IRS Employer Identification Number | ||||
1-16169 | EXELON CORPORATION | 23-2990190 | ||||
(a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (800) 483-3220 | ||||||
333-85496 | EXELON GENERATION COMPANY, LLC | 23-3064219 | ||||
(a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959 | ||||||
1-1839 | COMMONWEALTH EDISON COMPANY | 36-0938600 | ||||
(an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321 | ||||||
000-16844 | PECO ENERGY COMPANY | 23-0970240 | ||||
(a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000 | ||||||
1-1910 | 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 |
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 ¨☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Webweb site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 ofRegulation 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 ¨☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, or a smaller reporting company, or an emerging growth company. See definitionthe definitions of “large accelerated filer,” “accelerated filer” andfiler,” “smaller reporting company,” and “emerging growth company” inRule 12b-2 of the Exchange Act.
Large Accelerated Filer | Accelerated Filer | Non-accelerated Filer | Smaller Reporting Company | Emerging Growth Company | ||||||||||||||||
Exelon Corporation | ☒ | |||||||||||||||||||
Exelon Generation Company, LLC | ☒ | |||||||||||||||||||
Commonwealth Edison Company | ☒ | |||||||||||||||||||
PECO Energy Company | ☒ | |||||||||||||||||||
Baltimore Gas and Electric Company | ☒ | |||||||||||||||||||
Pepco Holdings LLC | ☒ | |||||||||||||||||||
Potomac Electric Power Company | ☒ | |||||||||||||||||||
Delmarva Power & Light Company | ☒ | |||||||||||||||||||
Atlantic City Electric Company | ☒ |
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 inRule 12b-2 of the Act). Yes ¨☐ No x☒
The number of shares outstanding of each registrant’s common stock as of September 30, 2016March 31, 2017 was:
Exelon Corporation Common Stock, without par value | ||
Exelon Generation Company, LLC | not applicable | |
Commonwealth Edison Company Common Stock, $12.50 par value | ||
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, $.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 |
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Consolidated Statements of Operations and Comprehensive Income | 51 | |||||
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ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | |||||
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ITEM 3. | ||||||
ITEM 4. | ||||||
PART II. | ||||||
ITEM 1. | ||||||
ITEM 1A. | ||||||
ITEM 4. | ||||||
ITEM 5. | 260 | |||||
ITEM 6. | ||||||
SIGNATURES | ||||||
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 | |
Pepco Energy Services or PES | Pepco Energy Services, Inc. and its subsidiaries | |
PCI | Potomac Capital Investment Corporation and its subsidiaries | |
DPL | Delmarva Power & Light Company | |
ACE | Atlantic City Electric Company | |
ACE Funding or ATF | Atlantic City Electric Transition Funding LLC | |
BSC | Exelon Business Services Company, LLC | |
PHISCO | PHI Service Company | |
Exelon Corporate | Exelon in its corporate capacity as a holding company | |
PHI Corporate | PHI in its corporate capacity as a holding company | |
Registrants | Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, collectively | |
Utility Registrants | ComEd, PECO, BGE, Pepco, DPL and ACE, collectively | |
AmerGen | AmerGen Energy Company, LLC | |
Antelope Valley | Antelope Valley Solar Ranch One | |
BondCo | RSB BondCo LLC | |
CENG | Constellation Energy Nuclear Group, LLC | |
ConEdison Solutions | The competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc., a subsidiary of Consolidated Edison, Inc. | |
Constellation | Constellation Energy Group, Inc. | |
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EGR | ExGen Renewables I, LLC | |
Entergy | Entergy Nuclear FitzPatrick LLC | |
Exelon Transmission Company | Exelon Transmission Company, LLC | |
Exelon Wind | Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC | |
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PEC L.P. | PECO Energy Capital, L.P. | |
PECO Trust III | PECO Capital Trust III | |
PECO Trust IV | PECO Energy Capital Trust IV | |
PETT | PECO Energy Transition Trust | |
| Renewable Power Generation | |
SolGen | SolGen, LLC | |
UII | Unicom Investments, Inc. | |
Ventures | Exelon |
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Other Terms and Abbreviations | ||||
Note “—” of the Exelon | Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s | |||
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Act 11 | Pennsylvania Act 11 of 2012 | |||
Act 129 | Pennsylvania Act 129 of 2008 | |||
AEC | Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source |
GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations | ||
AEPS | Pennsylvania Alternative Energy Portfolio Standards | |
AEPS Act | Pennsylvania Alternative Energy Portfolio Standards Act of 2004, as amended |
GLOSSARY OF TERMS AND ABBREVIATIONS
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AESO | Alberta Electric Systems Operator | |
AFUDC | Allowance for Funds Used During Construction | |
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AMI | Advanced Metering Infrastructure | |
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ARC | Asset Retirement Cost | |
ARO | Asset Retirement Obligation | |
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ASC | Accounting Standards Codification | |
BGS | Basic Generation Service | |
Block | Forward Purchase Energy Block Contracts | |
CAIR | Clean Air Interstate Rule | |
CAISO | California ISO | |
CAMR | Federal Clean Air Mercury Rule | |
CERCLA | Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended | |
CES | Clean Energy Standard | |
CFL | Compact Fluorescent Light | |
Clean Air Act | Clean Air Act of 1963, as amended | |
Clean Water Act | Federal Water Pollution Control Amendments of 1972, as amended | |
Competition Act | Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996 | |
Conectiv | Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE | |
Conectiv Energy | Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine in July 2010 | |
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CPUC | California Public Utilities Commission | |
CSAPR | Cross-State Air Pollution Rule | |
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D.C. Circuit Court | United States Court of Appeals for the District of Columbia Circuit | |
DCPSC | District of Columbia Public Service Commission | |
DC PLUG | District of Columbia Power Line Undergrounding | |
Default Electricity Supply | The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Standard Offer Service or BGS | |
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DOE | United States Department of Energy | |
DOJ | United States Department of Justice | |
DPSC | Delaware Public Service Commission | |
DRP | Direct Stock Purchase and Dividend Reinvestment Plan | |
DSP | Default Service Provider |
GLOSSARY OF TERMS AND ABBREVIATIONS
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DSP Program | Default Service Provider Program | |
EDCs | Electric distribution companies | |
EDF | Electricite de France SA and its subsidiaries | |
EE&C | Energy Efficiency and Conservation/Demand Response | |
EGS | Electric Generation Supplier | |
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EIMA | Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036) |
GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations | ||
EmPower Maryland | A Maryland demand-side management program for Pepco and DPL | |
EPA | United States Environmental Protection Agency | |
EPSA | Electric Power Supply Association | |
ERCOT | Electric Reliability Council of Texas | |
ERISA | Employee Retirement Income Security Act of 1974, as amended | |
EROA | Expected Rate of Return on Assets | |
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FASB | Financial Accounting Standards Board | |
FEJA | Illinois Public Act99-0906 or Future Energy Jobs Act | |
FERC | Federal Energy Regulatory Commission | |
FRCC | Florida Reliability Coordinating Council | |
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GAAP | Generally Accepted Accounting Principles in the United States | |
GCR | Gas Cost Rate | |
GHG | Greenhouse Gas | |
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GSA | Generation Supply Adjustment | |
GWh | Gigawatt hour | |
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Health Care Reform Acts | Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010 | |
HSR Act | The Hart-Scott-Rodino Antitrust Improvements Act of 1976 | |
IBEW | International Brotherhood of Electrical Workers | |
ICC | Illinois Commerce Commission | |
ICE | Intercontinental Exchange | |
Illinois Act | Illinois Electric Service Customer Choice and Rate Relief Law of 1997 | |
Illinois EPA | Illinois Environmental Protection Agency | |
Illinois Settlement Legislation | Legislation enacted in 2007 affecting electric utilities in Illinois | |
Integrys | Integrys Energy Services, Inc. | |
IPA | Illinois Power Agency | |
IRC | Internal Revenue Code | |
IRS | Internal Revenue Service | |
ISO | Independent System Operator | |
ISO-NE | ISO New England Inc. | |
ISO-NY | ISO New York | |
kV | Kilovolt | |
kW | Kilowatt | |
kWh | Kilowatt-hour | |
LIBOR | London Interbank Offered Rate | |
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LLRW | Low-Level Radioactive Waste | |
LT Plan | Long-term renewable resources procurement plan | |
LTIP | Long-Term Incentive Plan | |
MAPP | Mid-Atlantic Power Pathway |
GLOSSARY OF TERMS AND ABBREVIATIONS
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MATS | U.S. EPA Mercury and Air Toxics Rule | |
MBR | Market Based Rates Incentive | |
MDE | Maryland Department of the Environment | |
MDPSC | Maryland Public Service Commission | |
MGP | Manufactured Gas Plant | |
MISO | Midcontinent Independent System Operator, Inc. | |
mmcf | Million Cubic Feet | |
Moody’s | Moody’s Investor Service | |
MOPR | Minimum Offer Price Rule | |
MRV | Market-Related Value |
GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations | ||
MW | Megawatt | |
MWh | Megawatt hour | |
NAAQS | National Ambient Air Quality Standards | |
n.m. | not meaningful | |
NAV | Net Asset Value | |
NDT | Nuclear Decommissioning Trust | |
NEIL | Nuclear Electric Insurance Limited | |
NERC | North American Electric Reliability Corporation | |
NGS | Natural Gas Supplier | |
NJBPU | New Jersey Board of Public Utilities | |
NJDEP | New Jersey Department of Environmental Protection | |
Non-Regulatory Agreements Units | Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting | |
NOSA | Nuclear Operating Services Agreement | |
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NPDES | National Pollutant Discharge Elimination System | |
NRC | Nuclear Regulatory Commission | |
NSPS | New Source Performance Standards | |
NUGs | Non-utility generators | |
NWPA | Nuclear Waste Policy Act of 1982 | |
NYMEX | New York Mercantile Exchange | |
OCI | Other Comprehensive Income | |
OIESO | Ontario Independent Electricity System Operator | |
OPC | Office of People’s Counsel | |
OPEB | Other Postretirement Employee Benefits | |
PA DEP | Pennsylvania Department of Environmental Protection | |
PAPUC | Pennsylvania Public Utility Commission | |
PGC | Purchased Gas Cost Clause | |
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PJM | PJM Interconnection, LLC | |
POLR | Provider of Last Resort | |
POR | Purchase of Receivables | |
PPA | Power Purchase Agreement | |
Price-Anderson Act | Price-Anderson Nuclear Industries Indemnity Act of 1957 | |
Preferred Stock | Originally issued shares ofnon-voting,non-convertible andnon-transferable Series A preferred stock, par value $0.01 per share | |
PRP | Potentially Responsible Parties | |
PSEG | Public Service Enterprise Group Incorporated |
GLOSSARY OF TERMS AND ABBREVIATIONS
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PURTA | Pennsylvania Public Realty Tax Act | |
PV | Photovoltaic | |
RCRA | Resource Conservation and Recovery Act of 1976, as amended | |
REC | Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source | |
Regulatory Agreement Units | Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting | |
RES | Retail Electric Suppliers | |
RFP | Request for Proposal | |
Rider | Reconcilable Surcharge Recovery Mechanism | |
RGGI | Regional Greenhouse Gas Initiative |
GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations | ||
RMC | Risk Management Committee | |
ROE | Return on equity | |
RPM | PJM Reliability Pricing Model | |
RPS | Renewable Energy Portfolio Standards | |
RSSA | Reliability Support Services Agreement | |
RTEP | Regional Transmission Expansion Plan | |
RTO | Regional Transmission Organization | |
S&P | Standard & Poor’s Ratings Services | |
SEC | United States Securities and Exchange Commission | |
Senate Bill 1 | Maryland Senate Bill 1 | |
SERC | SERC Reliability Corporation (formerly Southeast Electric Reliability Council) | |
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SGIG | Smart Grid Investment Grant from DOE | |
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SILO | Sale-In,Lease-Out | |
SMPIP | Smart Meter Procurement and Installation Plan | |
SNF | Spent Nuclear Fuel | |
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SOS | Standard Offer Service | |
SPFPA | Security, Police and Fire Professionals of America | |
SPP | Southwest Power Pool | |
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Transition Bond Charge | Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees | |
Transition Bonds | Transition Bonds issued by ACE Funding | |
UGSOA | United Government Security Officers of America | |
Upstream | Natural gas exploration and production activities | |
VIE | Variable Interest Entity | |
WECC | Western Electric Coordinating Council | |
ZEC | Zero Emission Credit | |
ZES | Zero Emission Standard |
This combinedForm 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.
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. The factors that could cause actual results to differ materially from the forward-looking statements made by the RegistrantsExelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC (PHI), Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2015the Registrants’ combined 2016 Annual Report on Form10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 23;24, Commitments and Contingencies; and (2) PHI’s 2015 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 16; (3) this Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 18; and (4) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
WHERE TO FIND MORE INFORMATION
The public may read and copy any reports or other information that the Registrants file with the SEC at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the website maintained by the SEC atwww.sec.gov and the Registrants’ websites atwww.exeloncorp.com. Information contained on the Registrants’ websites shall not be deemed incorporated into, or to be a part of, this Report.
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
(In millions, except per share data) | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||
Operating revenues | ||||||||||||||||||||||||
Competitive businesses revenues | $ | 4,535 | $ | 4,564 | $ | 12,243 | $ | 14,278 | $ | 4,560 | $ | 4,473 | ||||||||||||
Rate-regulated utility revenues | 4,467 | 2,837 | 11,243 | 8,468 | 4,197 | 3,100 | ||||||||||||||||||
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Total operating revenues | 9,002 | 7,401 | 23,486 | 22,746 | 8,757 | 7,573 | ||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||
Competitive businesses purchased power and fuel | 2,584 | 2,515 | 6,599 | 7,789 | 2,795 | 2,440 | ||||||||||||||||||
Rate-regulated utility purchased power and fuel | 1,170 | 776 | 2,863 | 2,421 | 1,104 | 814 | ||||||||||||||||||
Operating and maintenance | 2,338 | 1,996 | 7,677 | 6,119 | 2,460 | 2,835 | ||||||||||||||||||
Depreciation and amortization | 1,195 | 606 | 2,821 | 1,818 | 896 | 685 | ||||||||||||||||||
Taxes other than income | 449 | 310 | 1,168 | 908 | 436 | 325 | ||||||||||||||||||
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Total operating expenses | 7,736 | 6,203 | 21,128 | 19,055 | 7,691 | 7,099 | ||||||||||||||||||
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Gain on sales of assets | 1 | 2 | 41 | 10 | 4 | 9 | ||||||||||||||||||
Bargain purchase gain | 226 | — | ||||||||||||||||||||||
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Operating income | 1,267 | 1,200 | 2,399 | 3,701 | 1,296 | 483 | ||||||||||||||||||
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Other income and (deductions) | ||||||||||||||||||||||||
Interest expense, net | (506 | ) | (243 | ) | (1,148 | ) | (724 | ) | (363 | ) | (277 | ) | ||||||||||||
Interest expense to affiliates | (10 | ) | (10 | ) | (31 | ) | (31 | ) | (10 | ) | (10 | ) | ||||||||||||
Other, net | 120 | (244 | ) | 377 | (179 | ) | 283 | 114 | ||||||||||||||||
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Total other income and (deductions) | (396 | ) | (497 | ) | (802 | ) | (934 | ) | (90 | ) | (173 | ) | ||||||||||||
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Income before income taxes | 871 | 703 | 1,597 | 2,767 | 1,206 | 310 | ||||||||||||||||||
Income taxes | 340 | 115 | 625 | 805 | 215 | 184 | ||||||||||||||||||
Equity in losses of unconsolidated affiliates | (5 | ) | (1 | ) | (16 | ) | (3 | ) | (10 | ) | (3 | ) | ||||||||||||
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Net income | 526 | 587 | 956 | 1,959 | 981 | 123 | ||||||||||||||||||
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Net income (loss) attributable to noncontrolling interests and preference stock dividends | 36 | (42 | ) | 26 | — | |||||||||||||||||||
Net loss attributable to noncontrolling interests and preference stock dividends | (14 | ) | (50 | ) | ||||||||||||||||||||
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Net income attributable to common shareholders | $ | 490 | $ | 629 | $ | 930 | $ | 1,959 | $ | 995 | $ | 173 | ||||||||||||
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Comprehensive income, net of income taxes | ||||||||||||||||||||||||
Net income | $ | 526 | $ | 587 | $ | 956 | $ | 1,959 | $ | 981 | $ | 123 | ||||||||||||
Other comprehensive income (loss), net of income taxes | ||||||||||||||||||||||||
Pension and non-pension postretirement benefit plans: | ||||||||||||||||||||||||
Prior service benefit reclassified to periodic benefit cost | (12 | ) | (11 | ) | (35 | ) | (35 | ) | (13 | ) | (12 | ) | ||||||||||||
Actuarial loss reclassified to periodic benefit cost | 47 | 55 | 140 | 165 | 49 | 46 | ||||||||||||||||||
Pension and non-pension postretirement benefit plan valuation adjustment | — | — | (3 | ) | (29 | ) | (59 | ) | (1 | ) | ||||||||||||||
Unrealized gain (loss) on cash flow hedges | 3 | (3 | ) | (4 | ) | 4 | 6 | (7 | ) | |||||||||||||||
Unrealized loss on equity investments | (4 | ) | — | (10 | ) | — | ||||||||||||||||||
Unrealized gain (loss) on foreign currency translation | 2 | (8 | ) | 8 | (17 | ) | ||||||||||||||||||
Unrealized loss on marketable securities | — | (1 | ) | — | — | |||||||||||||||||||
Unrealized gain (loss) on equity investments | 3 | (3 | ) | |||||||||||||||||||||
Unrealized gain on foreign currency translation | 1 | 6 | ||||||||||||||||||||||
Unrealized gain (loss) on marketable securities | 1 | (1 | ) | |||||||||||||||||||||
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Other comprehensive income | 36 | 32 | 96 | 88 | ||||||||||||||||||||
Other comprehensive (loss) income | (12 | ) | 28 | |||||||||||||||||||||
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Comprehensive income | 562 | 619 | 1,052 | 2,047 | 969 | 151 | ||||||||||||||||||
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Comprehensive income (loss) attributable to noncontrolling interests and preference stock dividends | 31 | (42 | ) | 21 | — | |||||||||||||||||||
Comprehensive loss attributable to noncontrolling interests and preference stock dividends | (16 | ) | (50 | ) | ||||||||||||||||||||
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Comprehensive income attributable to common shareholders | $ | 531 | $ | 661 | $ | 1,031 | $ | 2,047 | $ | 985 | $ | 201 | ||||||||||||
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Average shares of common stock outstanding: | ||||||||||||||||||||||||
Basic | 925 | 913 | 924 | 879 | 928 | 923 | ||||||||||||||||||
Diluted | 927 | 915 | 926 | 883 | 930 | 925 | ||||||||||||||||||
Earnings per average common share: | ||||||||||||||||||||||||
Basic | $ | 0.53 | $ | 0.69 | $ | 1.01 | $ | 2.23 | $ | 1.07 | $ | 0.19 | ||||||||||||
Diluted | $ | 0.53 | $ | 0.69 | $ | 1.00 | $ | 2.22 | $ | 1.07 | $ | 0.19 | ||||||||||||
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Dividends declared per common share | $ | 0.32 | $ | 0.31 | $ | 0.95 | $ | 0.93 | $ | 0.33 | $ | 0.31 | ||||||||||||
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended March 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 981 | $ | 123 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization | 1,274 | 1,063 | ||||||
Impairment of long-lived assets | 10 | 119 | ||||||
Gain on sales of assets | (4 | ) | (9 | ) | ||||
Bargain purchase gain | (226 | ) | — | |||||
Deferred income taxes and amortization of investment tax credits | 189 | 127 | ||||||
Net fair value changes related to derivatives | 47 | (107 | ) | |||||
Net realized and unrealized gains on nuclear decommissioning trust fund investments | (175 | ) | (55 | ) | ||||
Othernon-cash operating activities | 118 | 804 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | 313 | 117 | ||||||
Inventories | 109 | 142 | ||||||
Accounts payable and accrued expenses | (623 | ) | (571 | ) | ||||
Option premiums (paid) received, net | (6 | ) | 17 | |||||
Collateral (posted) received, net | (110 | ) | 206 | |||||
Income taxes | 50 | 47 | ||||||
Pension andnon-pension postretirement benefit contributions | (307 | ) | (239 | ) | ||||
Other assets and liabilities | (439 | ) | (311 | ) | ||||
|
|
|
| |||||
Net cash flows provided by operating activities | 1,201 | 1,473 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (2,114 | ) | (2,202 | ) | ||||
Proceeds from nuclear decommissioning trust fund sales | 1,767 | 2,240 | ||||||
Investment in nuclear decommissioning trust funds | (1,833 | ) | (2,297 | ) | ||||
Acquisition of businesses, net | (212 | ) | (6,645 | ) | ||||
Proceeds from termination of direct financing lease investment | — | 360 | ||||||
Change in restricted cash | (1 | ) | (2 | ) | ||||
Other investing activities | (18 | ) | (2 | ) | ||||
|
|
|
| |||||
Net cash flows used in investing activities | (2,411 | ) | (8,548 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Changes in short-term borrowings | 721 | 1,647 | ||||||
Proceeds from short-term borrowings with maturities greater than 90 days | 560 | 123 | ||||||
Repayments on short-term borrowings with maturities greater than 90 days | (500 | ) | — | |||||
Issuance of long-term debt | 763 | 151 | ||||||
Retirement of long-term debt | (65 | ) | (116 | ) | ||||
Dividends paid on common stock | (303 | ) | (287 | ) | ||||
Proceeds from employee stock plans | 12 | 9 | ||||||
Other financing activities | (4 | ) | 6 | |||||
|
|
|
| |||||
Net cash flows provided by financing activities | 1,184 | 1,533 | ||||||
|
|
|
| |||||
Decrease in cash and cash equivalents | (26 | ) | (5,542 | ) | ||||
Cash and cash equivalents at beginning of period | 635 | 6,502 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 609 | $ | 960 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions) | March 31, 2017 | December 31, 2016 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 609 | $ | 635 | ||||
Restricted cash and cash equivalents | 254 | 253 | ||||||
Deposit with IRS | 1,250 | 1,250 | ||||||
Accounts receivable, net | ||||||||
Customer | 3,886 | 4,158 | ||||||
Other | 1,133 | 1,201 | ||||||
Mark-to-market derivative assets | 847 | 917 | ||||||
Unamortized energy contract assets | 103 | 88 | ||||||
Inventories, net | ||||||||
Fossil fuel and emission allowances | 249 | 364 | ||||||
Materials and supplies | 1,312 | 1,274 | ||||||
Regulatory assets | 1,330 | 1,342 | ||||||
Other | 1,221 | 930 | ||||||
|
|
|
| |||||
Total current assets | 12,194 | 12,412 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 72,630 | 71,555 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 10,051 | 10,046 | ||||||
Nuclear decommissioning trust funds | 12,362 | 11,061 | ||||||
Investments | 648 | 629 | ||||||
Goodwill | 6,677 | 6,677 | ||||||
Mark-to-market derivative assets | 539 | 492 | ||||||
Unamortized energy contract assets | 432 | 447 | ||||||
Pledged assets for Zion Station decommissioning | 95 | 113 | ||||||
Other | 1,440 | 1,472 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 32,244 | 30,937 | ||||||
|
|
|
| |||||
Total assets(a) | $ | 117,068 | $ | 114,904 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWSBALANCE SHEETS
(Unaudited)
Nine Months Ended September 30, | ||||||||
(In millions) | 2016 | 2015 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 956 | $ | 1,959 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization | 4,009 | 2,930 | ||||||
Impairment of long-lived assets and losses on regulatory assets | 274 | 25 | ||||||
Gain on sales of assets | (41 | ) | (10 | ) | ||||
Deferred income taxes and amortization of investment tax credits | 623 | 241 | ||||||
Net fair value changes related to derivatives | 100 | (363 | ) | |||||
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | (243 | ) | 221 | |||||
Other non-cash operating activities | 1,224 | 856 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (296 | ) | 175 | |||||
Inventories | 21 | 65 | ||||||
Accounts payable and accrued expenses | 296 | (115 | ) | |||||
Option premiums (paid) received, net | (24 | ) | 27 | |||||
Collateral received, net | 757 | 115 | ||||||
Income taxes | 527 | 300 | ||||||
Pension and non-pension postretirement benefit contributions | (283 | ) | (430 | ) | ||||
Other assets and liabilities | (537 | ) | (322 | ) | ||||
|
|
|
| |||||
Net cash flows provided by operating activities | 7,363 | 5,674 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (6,368 | ) | (5,443 | ) | ||||
Proceeds from nuclear decommissioning trust fund sales | 7,914 | 4,551 | ||||||
Investment in nuclear decommissioning trust funds | (8,093 | ) | (4,737 | ) | ||||
Acquisition of businesses, net of cash acquired | (6,896 | ) | (28 | ) | ||||
Proceeds from sales of long-lived assets | 49 | 145 | ||||||
Proceeds from termination of direct financing lease investment | 360 | — | ||||||
Change in restricted cash | (75 | ) | (70 | ) | ||||
Other investing activities | (110 | ) | (107 | ) | ||||
|
|
|
| |||||
Net cash flows used in investing activities | (13,219 | ) | (5,689 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Changes in short-term borrowings | (1,014 | ) | 230 | |||||
Proceeds from short-term borrowings with maturities greater than 90 days | 195 | — | ||||||
Repayments on short-term borrowings with maturities greater than 90 days | (452 | ) | — | |||||
Issuance of long-term debt | 4,488 | 5,909 | ||||||
Retirement of long-term debt | (944 | ) | (1,745 | ) | ||||
Restricted proceeds from issuance of long-term debt | (30 | ) | — | |||||
Issuance of common stock | — | 1,868 | ||||||
Redemption of preference stock | (190 | ) | — | |||||
Dividends paid on common stock | (873 | ) | (819 | ) | ||||
Proceeds from employee stock plans | 36 | 24 | ||||||
Other financing activities | 35 | (65 | ) | |||||
|
|
|
| |||||
Net cash flows provided by financing activities | 1,251 | 5,402 | ||||||
|
|
|
| |||||
(Decrease) Increase in cash and cash equivalents | (4,605 | ) | 5,387 | |||||
Cash and cash equivalents at beginning of period | 6,502 | 1,878 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 1,897 | $ | 7,265 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON CORPORATION AND SUBSIDIARY COMPANIES
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | ||||||
(Unaudited) | ||||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 1,897 | $ | 6,502 | ||||
Restricted cash and cash equivalents | 321 | 205 | ||||||
Accounts receivable, net | ||||||||
Customer | 4,061 | 3,187 | ||||||
Other | 1,013 | 912 | ||||||
Mark-to-market derivative assets | 754 | 1,365 | ||||||
Unamortized energy contract assets | 126 | 86 | ||||||
Inventories, net | ||||||||
Fossil fuel and emission allowances | 374 | 462 | ||||||
Materials and supplies | 1,188 | 1,104 | ||||||
Regulatory assets | 1,410 | 759 | ||||||
Other | 1,064 | 752 | ||||||
|
|
|
| |||||
Total current assets | 12,208 | 15,334 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 71,214 | 57,439 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 10,022 | 6,065 | ||||||
Nuclear decommissioning trust funds | 11,076 | 10,342 | ||||||
Investments | 592 | 639 | ||||||
Goodwill | 6,672 | 2,672 | ||||||
Mark-to-market derivative assets | 669 | 758 | ||||||
Unamortized energy contract assets | 473 | 484 | ||||||
Pledged assets for Zion Station decommissioning | 135 | 206 | ||||||
Other | 1,474 | 1,445 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 31,113 | 22,611 | ||||||
|
|
|
| |||||
Total assets(a) | $ | 114,535 | $ | 95,384 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON CORPORATION AND SUBSIDIARY COMPANIES
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | ||||||||||||
(Unaudited) | ||||||||||||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||||||||||
Current liabilities | ||||||||||||||||
Short-term borrowings | $ | 567 | $ | 533 | $ | 2,048 | $ | 1,267 | ||||||||
Long-term debt due within one year | 2,512 | 1,500 | 3,645 | 2,430 | ||||||||||||
Accounts payable | 3,044 | 2,883 | 3,011 | 3,441 | ||||||||||||
Accrued expenses | 3,236 | 2,376 | 3,007 | 3,460 | ||||||||||||
Payables to affiliates | 8 | 8 | 8 | 8 | ||||||||||||
Regulatory liabilities | 548 | 369 | 637 | 602 | ||||||||||||
Mark-to-market derivative liabilities | 222 | 205 | 228 | 282 | ||||||||||||
Unamortized energy contract liabilities | 452 | 100 | 388 | 407 | ||||||||||||
Renewable energy credit obligation | 356 | 302 | 400 | 428 | ||||||||||||
PHI merger related obligation | 145 | — | 123 | 151 | ||||||||||||
Other | 1,068 | 842 | 942 | 981 | ||||||||||||
|
|
|
| |||||||||||||
Total current liabilities | 12,158 | 9,118 | 14,437 | 13,457 | ||||||||||||
|
|
|
| |||||||||||||
Long-term debt | 32,330 | 23,645 | 31,044 | 31,575 | ||||||||||||
Long-term debt to financing trusts | 642 | 641 | 641 | 641 | ||||||||||||
Deferred credits and other liabilities | ||||||||||||||||
Deferred income taxes and unamortized investment tax credits | 18,115 | 13,776 | 18,518 | 18,138 | ||||||||||||
Asset retirement obligations | 9,348 | 8,585 | 9,634 | 9,111 | ||||||||||||
Pension obligations | 3,765 | 3,385 | 4,082 | 4,248 | ||||||||||||
Non-pension postretirement benefit obligations | 1,921 | 1,618 | 1,928 | 1,848 | ||||||||||||
Spent nuclear fuel obligation | 1,023 | 1,021 | 1,136 | 1,024 | ||||||||||||
Regulatory liabilities | 4,437 | 4,201 | 4,302 | 4,187 | ||||||||||||
Mark-to-market derivative liabilities | 422 | 374 | 420 | 392 | ||||||||||||
Unamortized energy contract liabilities | 927 | 117 | 779 | 830 | ||||||||||||
Payable for Zion Station decommissioning | 33 | 90 | 3 | 14 | ||||||||||||
Other | 1,928 | 1,491 | 1,853 | 1,827 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred credits and other liabilities | 41,919 | 34,658 | 42,655 | 41,619 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities(a) | 87,049 | 68,062 | 88,777 | 87,292 | ||||||||||||
|
|
|
| |||||||||||||
Commitments and contingencies | ||||||||||||||||
Contingently redeemable noncontrolling interests | 26 | 28 | ||||||||||||||
Shareholders’ equity | ||||||||||||||||
Common stock (No par value, 2000 shares authorized, 923 shares and 920 shares outstanding at September 30, 2016 and December 31, 2015, respectively) | 18,756 | 18,676 | ||||||||||||||
Treasury stock, at cost (35 shares at September 30, 2016 and December 31, 2015, respectively) | (2,327 | ) | (2,327 | ) | ||||||||||||
Common stock (No par value, 2000 shares authorized, 926 shares and 924 shares outstanding at March 31, 2017 and December 31, 2016, respectively) | 18,807 | 18,794 | ||||||||||||||
Treasury stock, at cost (35 shares at March 31, 2017 and December 31, 2016, respectively) | (2,327 | ) | (2,327 | ) | ||||||||||||
Retained earnings | 12,121 | 12,068 | 12,720 | 12,030 | ||||||||||||
Accumulated other comprehensive loss, net | (2,523 | ) | (2,624 | ) | (2,670 | ) | (2,660 | ) | ||||||||
|
|
|
| |||||||||||||
Total shareholders’ equity | 26,027 | 25,793 | 26,530 | 25,837 | ||||||||||||
BGE preference stock not subject to mandatory redemption | — | 193 | ||||||||||||||
Noncontrolling interests | 1,433 | 1,308 | 1,761 | 1,775 | ||||||||||||
|
|
|
| |||||||||||||
Total equity | 27,460 | 27,294 | 28,291 | 27,612 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities and shareholders’ equity | $ | 114,535 | $ | 95,384 | $ | 117,068 | $ | 114,904 | ||||||||
|
|
|
|
(a) | Exelon’s consolidated assets include |
See the Combined Notes to Consolidated Financial Statements
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
(In millions, shares in thousands) | Issued Shares | Common Stock | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Loss, net | Noncontrolling Interests | Preference Stock | Total Shareholders’ Equity | ||||||||||||||||||||||||
Balance, December 31, 2015 | 954,668 | $ | 18,676 | $ | (2,327 | ) | $ | 12,068 | $ | (2,624 | ) | $ | 1,308 | $ | 193 | $ | 27,294 | |||||||||||||||
Net income | — | — | — | 930 | — | 18 | 8 | 956 | ||||||||||||||||||||||||
Long-term incentive plan activity | 2,422 | 61 | — | — | — | — | — | 61 | ||||||||||||||||||||||||
Employee stock purchase plan issuances | 924 | 36 | — | — | — | — | — | 36 | ||||||||||||||||||||||||
Tax benefit on stock compensation | — | (17 | ) | — | — | — | — | — | (17 | ) | ||||||||||||||||||||||
Changes in equity of noncontrolling interests | — | — | — | — | — | 5 | — | 5 | ||||||||||||||||||||||||
Adjustment of contingently redeemable noncontrolling interest due to release of contingency | — | — | — | — | — | 107 | — | 107 | ||||||||||||||||||||||||
Common stock dividends | — | — | — | (877 | ) | — | — | — | (877 | ) | ||||||||||||||||||||||
Redemption of preference stock | — | — | — | — | — | — | (193 | ) | (193 | ) | ||||||||||||||||||||||
Preference stock dividends | — | — | — | — | — | — | (8 | ) | (8 | ) | ||||||||||||||||||||||
Other comprehensive income (loss), net of income taxes | — | — | — | — | 101 | (5 | ) | — | 96 | |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Balance, September 30, 2016 | 958,014 | $ | 18,756 | $ | (2,327 | ) | $ | 12,121 | $ | (2,523 | ) | $ | 1,433 | $ | — | $ | 27,460 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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, 2016 | 958,778 | $ | 18,794 | $ | (2,327 | ) | $ | 12,030 | $ | (2,660 | ) | $ | 1,775 | $ | 27,612 | |||||||||||||
Net income (loss) | — | — | — | 995 | — | (14 | ) | 981 | ||||||||||||||||||||
Long-term incentive plan activity | 1,739 | 1 | — | — | — | — | 1 | |||||||||||||||||||||
Employee stock purchase plan issuances | 323 | 12 | — | — | — | — | 12 | |||||||||||||||||||||
Changes in equity of noncontrolling interests | — | — | — | — | — | 2 | 2 | |||||||||||||||||||||
Common stock dividends | — | — | — | (305 | ) | — | — | (305 | ) | |||||||||||||||||||
Other comprehensive loss, net of income taxes | — | — | — | — | (10 | ) | (2 | ) | (12 | ) | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Balance at March 31, 2017 | 960,840 | $ | 18,807 | $ | (2,327 | ) | $ | 12,720 | $ | (2,670 | ) | $ | 1,761 | $ | 28,291 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
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, | Three Months Ended March 31, | ||||||||||||||||||||||
(In millions) | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||
Operating revenues | ||||||||||||||||||||||||
Operating revenues | $ | 4,533 | $ | 4,562 | $ | 12,234 | $ | 14,270 | $ | 4,558 | $ | 4,471 | ||||||||||||
Operating revenues from affiliates | 502 | 206 | 1,129 | 571 | 330 | 268 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total operating revenues | 5,035 | 4,768 | 13,363 | 14,841 | 4,888 | 4,739 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||
Purchased power and fuel | 2,584 | 2,516 | 6,599 | 7,789 | 2,796 | 2,440 | ||||||||||||||||||
Purchased power and fuel from affiliates | 5 | 3 | 10 | 11 | 2 | 2 | ||||||||||||||||||
Operating and maintenance | 1,189 | 1,088 | 3,855 | 3,399 | 1,309 | 1,296 | ||||||||||||||||||
Operating and maintenance from affiliates | 147 | 153 | 478 | 461 | 179 | 171 | ||||||||||||||||||
Depreciation and amortization | 632 | 264 | 1,329 | 774 | 302 | 289 | ||||||||||||||||||
Taxes other than income | 136 | 123 | 380 | 369 | 143 | 126 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total operating expenses | 4,693 | 4,147 | 12,651 | 12,803 | 4,731 | 4,324 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Gain on sales of assets | — | 1 | 31 | 7 | 4 | — | ||||||||||||||||||
Bargain purchase gain | 226 | — | ||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Operating income | 342 | 622 | 743 | 2,045 | 387 | 415 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Other income and (deductions) | ||||||||||||||||||||||||
Interest expense, net | (67 | ) | (56 | ) | (243 | ) | (236 | ) | (90 | ) | (87 | ) | ||||||||||||
Interest expense to affiliates | (10 | ) | (12 | ) | (30 | ) | (33 | ) | (10 | ) | (10 | ) | ||||||||||||
Other, net | 185 | (257 | ) | 395 | (193 | ) | 259 | 93 | ||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total other income and (deductions) | 108 | (325 | ) | 122 | (462 | ) | 159 | (4 | ) | |||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Income before income taxes | 450 | 297 | 865 | 1,583 | 546 | 411 | ||||||||||||||||||
Income taxes | 173 | (36 | ) | 293 | 371 | 127 | 151 | |||||||||||||||||
Equity in losses of unconsolidated affiliates | (6 | ) | (1 | ) | (16 | ) | (4 | ) | (10 | ) | (3 | ) | ||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Net income | 271 | 332 | 556 | 1,208 | 409 | 257 | ||||||||||||||||||
Net income (loss) attributable to noncontrolling interests | 35 | (45 | ) | 18 | (10 | ) | ||||||||||||||||||
Net loss attributable to noncontrolling interests | (14 | ) | (53 | ) | ||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Net income attributable to membership interest | $ | 236 | $ | 377 | $ | 538 | $ | 1,218 | $ | 423 | $ | 310 | ||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Comprehensive income, net of income taxes | ||||||||||||||||||||||||
Net income | $ | 271 | $ | 332 | $ | 556 | $ | 1,208 | $ | 409 | $ | 257 | ||||||||||||
Other comprehensive income (loss), net of income taxes | ||||||||||||||||||||||||
Unrealized gain (loss) on cash flow hedges | 1 | (3 | ) | (3 | ) | (7 | ) | 6 | (5 | ) | ||||||||||||||
Unrealized loss on equity investments | — | — | (4 | ) | — | |||||||||||||||||||
Unrealized gain (loss) on foreign currency translation | 2 | (8 | ) | 8 | (17 | ) | ||||||||||||||||||
Unrealized gain (loss) on marketable securities | 1 | (2 | ) | 1 | — | |||||||||||||||||||
Unrealized gain (loss) on equity investments | 4 | (2 | ) | |||||||||||||||||||||
Unrealized gain on foreign currency translation | 1 | 6 | ||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Other comprehensive income (loss) | 4 | (13 | ) | 2 | (24 | ) | 11 | (1 | ) | |||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Comprehensive income | 275 | 319 | 558 | 1,184 | 420 | 256 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Comprehensive income (loss) attributable to noncontrolling interests | 30 | (45 | ) | 13 | (10 | ) | ||||||||||||||||||
Comprehensive loss attributable to noncontrolling interests | (16 | ) | (53 | ) | ||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Comprehensive income attributable to membership interest | $ | 245 | $ | 364 | $ | 545 | $ | 1,194 | $ | 436 | $ | 309 | ||||||||||||
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||
(In millions) | 2016 | 2015 | 2017 | 2016 | ||||||||||||
Cash flows from operating activities | ||||||||||||||||
Net income | $ | 556 | $ | 1,208 | $ | 409 | $ | 257 | ||||||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||||||||||
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization | 2,516 | 1,887 | ||||||||||||||
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization | 678 | 667 | ||||||||||||||
Impairment of long-lived assets | 209 | 1 | 10 | 119 | ||||||||||||
Gain on sales of assets | (31 | ) | (7 | ) | (4 | ) | — | |||||||||
Bargain purchase gain | (226 | ) | — | |||||||||||||
Deferred income taxes and amortization of investment tax credits | (133 | ) | 21 | 112 | 68 | |||||||||||
Net fair value changes related to derivatives | 112 | (252 | ) | 51 | (106 | ) | ||||||||||
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | (243 | ) | 221 | |||||||||||||
Net realized and unrealized gains on nuclear decommissioning trust fund investments | (175 | ) | (55 | ) | ||||||||||||
Other non-cash operating activities | 129 | 227 | (10 | ) | 51 | |||||||||||
Changes in assets and liabilities: | ||||||||||||||||
Accounts receivable | 26 | 252 | 195 | 173 | ||||||||||||
Receivables from and payables to affiliates, net | (56 | ) | 16 | 23 | (17 | ) | ||||||||||
Inventories | 18 | 69 | 81 | 93 | ||||||||||||
Accounts payable and accrued expenses | 9 | (146 | ) | 62 | (363 | ) | ||||||||||
Option premiums (paid) received, net | (24 | ) | 27 | (6 | ) | 17 | ||||||||||
Collateral received, net | 759 | 186 | ||||||||||||||
Collateral (posted) received, net | (102 | ) | 198 | |||||||||||||
Income taxes | 202 | (70 | ) | (81 | ) | (60 | ) | |||||||||
Pension and non-pension postretirement benefit contributions | (122 | ) | (189 | ) | (110 | ) | (112 | ) | ||||||||
Other assets and liabilities | (204 | ) | (245 | ) | (167 | ) | (148 | ) | ||||||||
|
|
|
| |||||||||||||
Net cash flows provided by operating activities | 3,723 | 3,206 | 740 | 782 | ||||||||||||
|
|
|
| |||||||||||||
Cash flows from investing activities | ||||||||||||||||
Capital expenditures | (2,651 | ) | (2,774 | ) | (923 | ) | (1,125 | ) | ||||||||
Proceeds from nuclear decommissioning trust fund sales | 7,914 | 4,551 | 1,767 | 2,240 | ||||||||||||
Investment in nuclear decommissioning trust funds | (8,093 | ) | (4,737 | ) | (1,833 | ) | (2,297 | ) | ||||||||
Acquisition of businesses | (255 | ) | (28 | ) | ||||||||||||
Proceeds from sale of long-lived assets | 30 | 144 | ||||||||||||||
Acquisition of businesses, net | (212 | ) | (1 | ) | ||||||||||||
Change in restricted cash | (39 | ) | (84 | ) | 18 | 4 | ||||||||||
Other investing activities | (184 | ) | (92 | ) | (29 | ) | (25 | ) | ||||||||
|
|
|
| |||||||||||||
Net cash flows used in investing activities | (3,278 | ) | (3,020 | ) | (1,212 | ) | (1,204 | ) | ||||||||
|
|
|
| |||||||||||||
Cash flows from financing activities | ||||||||||||||||
Changes in short-term borrowings | (42 | ) | 1,377 | |||||||||||||
Proceeds from short-term borrowings with maturities greater than 90 days | 195 | — | 60 | 123 | ||||||||||||
Repayments of short-term borrowings with maturities greater than 90 days | (152 | ) | — | |||||||||||||
Issuance of long-term debt | 338 | 1,307 | 762 | 151 | ||||||||||||
Retirement of long-term debt | (164 | ) | (64 | ) | (30 | ) | (94 | ) | ||||||||
Retirement of long-term debt to affiliate | — | (550 | ) | |||||||||||||
Changes in Exelon intercompany money pool | (785 | ) | 1,205 | (1 | ) | (1,183 | ) | |||||||||
Distribution to member | (167 | ) | (2,368 | ) | (164 | ) | (55 | ) | ||||||||
Contribution from member | 142 | 55 | — | 44 | ||||||||||||
Other financing activities | 92 | (6 | ) | (3 | ) | 5 | ||||||||||
|
|
|
| |||||||||||||
Net cash flows used in financing activities | (501 | ) | (421 | ) | ||||||||||||
Net cash flows provided by financing activities | 582 | 368 | ||||||||||||||
|
|
|
| |||||||||||||
Decrease in cash and cash equivalents | (56 | ) | (235 | ) | ||||||||||||
Increase (Decrease) in cash and cash equivalents | 110 | (54 | ) | |||||||||||||
Cash and cash equivalents at beginning of period | 431 | 780 | 290 | 431 | ||||||||||||
|
|
|
| |||||||||||||
Cash and cash equivalents at end of period | $ | 375 | $ | 545 | $ | 400 | $ | 377 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | ||||||||||||
(Unaudited) | ||||||||||||||||
ASSETS | ||||||||||||||||
Current assets | ||||||||||||||||
Cash and cash equivalents | $ | 375 | $ | 431 | $ | 400 | $ | 290 | ||||||||
Restricted cash and cash equivalents | 162 | 123 | 140 | 158 | ||||||||||||
Accounts receivable, net | ||||||||||||||||
Customer | 2,318 | 2,095 | 2,278 | 2,433 | ||||||||||||
Other | 301 | 360 | 545 | 558 | ||||||||||||
Mark-to-market derivative assets | 754 | 1,365 | 847 | 917 | ||||||||||||
Receivables from affiliates | 170 | 83 | 141 | 156 | ||||||||||||
Unamortized energy contract assets | 126 | 86 | 103 | 88 | ||||||||||||
Inventories, net | ||||||||||||||||
Fossil fuel and emission allowances | 292 | 384 | 222 | 292 | ||||||||||||
Materials and supplies | 849 | 880 | 957 | 935 | ||||||||||||
Other | 788 | 535 | 881 | 701 | ||||||||||||
|
|
|
| |||||||||||||
Total current assets | 6,135 | 6,342 | 6,514 | 6,528 | ||||||||||||
|
|
|
| |||||||||||||
Property, plant and equipment, net | 26,374 | 25,843 | 25,893 | 25,585 | ||||||||||||
Deferred debits and other assets | ||||||||||||||||
Nuclear decommissioning trust funds | 11,076 | 10,342 | 12,362 | 11,061 | ||||||||||||
Investments | 381 | 210 | 435 | 418 | ||||||||||||
Goodwill | 47 | 47 | 47 | 47 | ||||||||||||
Mark-to-market derivative assets | 630 | 733 | 527 | 476 | ||||||||||||
Prepaid pension asset | 1,621 | 1,689 | 1,646 | 1,595 | ||||||||||||
Pledged assets for Zion Station decommissioning | 135 | 206 | 95 | 113 | ||||||||||||
Unamortized energy contract assets | 472 | 484 | 432 | 447 | ||||||||||||
Deferred income taxes | 5 | 6 | 10 | 16 | ||||||||||||
Other | 692 | 627 | 648 | 688 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred debits and other assets | 15,059 | 14,344 | 16,202 | 14,861 | ||||||||||||
|
|
|
| |||||||||||||
Total assets(a) | $ | 47,568 | $ | 46,529 | $ | 48,609 | $ | 46,974 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | ||||||||||||
(Unaudited) | ||||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||
Current liabilities | ||||||||||||||||
Short-term borrowings | $ | 40 | $ | 29 | $ | 717 | $ | 699 | ||||||||
Long-term debt due within one year | 254 | 90 | 1,156 | 1,117 | ||||||||||||
Accounts payable | 1,465 | 1,583 | 1,482 | 1,610 | ||||||||||||
Accrued expenses | 942 | 935 | 720 | 989 | ||||||||||||
Payables to affiliates | 118 | 104 | 145 | 137 | ||||||||||||
Borrowings from Exelon intercompany money pool | 461 | 1,252 | 54 | 55 | ||||||||||||
Mark-to-market derivative liabilities | 203 | 182 | 209 | 263 | ||||||||||||
Unamortized energy contract liabilities | 76 | 100 | 68 | 72 | ||||||||||||
Renewable energy credit obligation | 356 | 302 | 400 | 428 | ||||||||||||
Other | 392 | 356 | 286 | 313 | ||||||||||||
|
|
|
| |||||||||||||
Total current liabilities | 4,307 | 4,933 | 5,237 | 5,683 | ||||||||||||
|
|
|
| |||||||||||||
Long-term debt | 8,077 | 7,936 | 7,904 | 7,202 | ||||||||||||
Long-term debt to affiliate | 924 | 933 | 919 | 922 | ||||||||||||
Deferred credits and other liabilities | ||||||||||||||||
Deferred income taxes and unamortized investment tax credits | 5,684 | 5,845 | 5,850 | 5,585 | ||||||||||||
Asset retirement obligations | 9,160 | 8,431 | 9,444 | 8,922 | ||||||||||||
Non-pension postretirement benefit obligations | 932 | 924 | 926 | 930 | ||||||||||||
Spent nuclear fuel obligation | 1,023 | 1,021 | 1,136 | 1,024 | ||||||||||||
Payables to affiliates | 2,704 | 2,577 | 2,776 | 2,608 | ||||||||||||
Mark-to-market derivative liabilities | 197 | 150 | 157 | 153 | ||||||||||||
Unamortized energy contract liabilities | 97 | 117 | 78 | 80 | ||||||||||||
Payable for Zion Station decommissioning | 33 | 90 | 3 | 14 | ||||||||||||
Other | 691 | 602 | 615 | 595 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred credits and other liabilities | 20,521 | 19,757 | 20,985 | 19,911 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities(a) | 33,829 | 33,559 | 35,045 | 33,718 | ||||||||||||
|
|
|
| |||||||||||||
Commitments and contingencies | ||||||||||||||||
Contingently redeemable noncontrolling interests | 26 | 28 | ||||||||||||||
Equity | ||||||||||||||||
Member’s equity | ||||||||||||||||
Membership interest | 9,265 | 8,997 | 9,310 | 9,261 | ||||||||||||
Undistributed earnings | 3,072 | 2,701 | 2,534 | 2,275 | ||||||||||||
Accumulated other comprehensive loss, net | (56 | ) | (63 | ) | (41 | ) | (54 | ) | ||||||||
|
|
|
| |||||||||||||
Total member’s equity | 12,281 | 11,635 | 11,803 | 11,482 | ||||||||||||
Noncontrolling interests | 1,432 | 1,307 | 1,761 | 1,774 | ||||||||||||
|
|
|
| |||||||||||||
Total equity | 13,713 | 12,942 | 13,564 | 13,256 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities and equity | $ | 47,568 | $ | 46,529 | $ | 48,609 | $ | 46,974 | ||||||||
|
|
|
|
(a) | Generation’s consolidated assets include |
See the Combined Notes to Consolidated Financial Statements
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)
Member’s Equity | ||||||||||||||||||||
(In millions) | Membership Interest | Undistributed Earnings | Accumulated Other Comprehensive Loss, net | Noncontrolling Interests | Total Equity | |||||||||||||||
Balance, December 31, 2015 | $ | 8,997 | $ | 2,701 | $ | (63 | ) | $ | 1,307 | $ | 12,942 | |||||||||
Net income | — | 538 | — | 18 | 556 | |||||||||||||||
Changes in equity of noncontrolling interests | — | — | — | 5 | 5 | |||||||||||||||
Adjustment of contingently redeemable noncontrolling interests due to release of contingency | — | — | — | 107 | 107 | |||||||||||||||
Allocation of tax benefit from member | 98 | — | — | — | 98 | |||||||||||||||
Contribution from member | 170 | — | — | — | 170 | |||||||||||||||
Distribution to member | — | (167 | ) | — | — | (167 | ) | |||||||||||||
Other comprehensive income (loss), net of income taxes | — | — | 7 | (5 | ) | 2 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Balance, September 30, 2016 | $ | 9,265 | $ | 3,072 | $ | (56 | ) | $ | 1,432 | $ | 13,713 | |||||||||
|
|
|
|
|
|
|
|
|
|
Member’s Equity | ||||||||||||||||||||
(In millions) | Membership Interest | Undistributed Earnings | Accumulated Other Comprehensive Loss, net | Noncontrolling Interests | Total Equity | |||||||||||||||
Balance, December 31, 2016 | $ | 9,261 | $ | 2,275 | $ | (54 | ) | $ | 1,774 | $ | 13,256 | |||||||||
Net income (loss) | — | 423 | — | (14 | ) | 409 | ||||||||||||||
Changes in equity of noncontrolling interests | — | — | — | 3 | 3 | |||||||||||||||
Distribution of net retirement benefit obligation to member | 49 | — | — | — | 49 | |||||||||||||||
Distribution to member | — | (164 | ) | — | — | (164 | ) | |||||||||||||
Other comprehensive income (loss), net of income taxes | — | — | 13 | (2 | ) | 11 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Balance, March 31, 2017 | $ | 9,310 | $ | 2,534 | $ | (41 | ) | $ | 1,761 | $ | 13,564 | |||||||||
|
|
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
(In millions) | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||
Operating revenues | ||||||||||||||||||||||||
Electric operating revenues | $ | 1,493 | $ | 1,375 | $ | 4,019 | $ | 3,706 | $ | 1,293 | $ | 1,244 | ||||||||||||
Operating revenues from affiliates | 4 | 1 | 12 | 3 | 5 | 5 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total operating revenues | 1,497 | 1,376 | 4,031 | 3,709 | 1,298 | 1,249 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||
Purchased power | 435 | 388 | 1,104 | 974 | 329 | 343 | ||||||||||||||||||
Purchased power from affiliate | 19 | 2 | 37 | 17 | 5 | 5 | ||||||||||||||||||
Operating and maintenance | 327 | 353 | 950 | 1,023 | 307 | 305 | ||||||||||||||||||
Operating and maintenance from affiliate | 50 | 51 | 163 | 143 | 63 | 63 | ||||||||||||||||||
Depreciation and amortization | 196 | 176 | 574 | 528 | 208 | 189 | ||||||||||||||||||
Taxes other than income | 82 | 79 | 222 | 225 | 72 | 75 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total operating expenses | 1,109 | 1,049 | 3,050 | 2,910 | 984 | 980 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Gain on sale of assets | 1 | — | 6 | — | — | 5 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Operating income | 389 | 327 | 987 | 799 | 314 | 274 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Other income and (deductions) | ||||||||||||||||||||||||
Interest expense, net | (194 | ) | (80 | ) | (364 | ) | (238 | ) | (82 | ) | (83 | ) | ||||||||||||
Interest expense to affiliates | (3 | ) | (3 | ) | (10 | ) | (10 | ) | (3 | ) | (3 | ) | ||||||||||||
Other, net | (80 | ) | 4 | (72 | ) | 14 | 4 | 4 | ||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total other income and (deductions) | (277 | ) | (79 | ) | (446 | ) | (234 | ) | (81 | ) | (82 | ) | ||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Income before income taxes | 112 | 248 | 541 | 565 | 233 | 192 | ||||||||||||||||||
Income taxes | 75 | 99 | 244 | 226 | 92 | 77 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Net income | $ | 37 | $ | 149 | $ | 297 | $ | 339 | $ | 141 | $ | 115 | ||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Comprehensive income | $ | 37 | $ | 149 | $ | 297 | $ | 339 | $ | 141 | $ | 115 | ||||||||||||
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30, | ||||||||
(In millions) | 2016 | 2015 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 297 | $ | 339 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion | 574 | 528 | ||||||
Deferred income taxes and amortization of investment tax credits | 398 | 107 | ||||||
Other non-cash operating activities | 122 | 312 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (55 | ) | (114 | ) | ||||
Receivables from and payables to affiliates, net | (9 | ) | (23 | ) | ||||
Inventories | 4 | (23 | ) | |||||
Accounts payable and accrued expenses | 145 | (18 | ) | |||||
Collateral posted, net | (2 | ) | (43 | ) | ||||
Income taxes | 206 | 389 | ||||||
Pension and non-pension postretirement benefit contributions | (35 | ) | (142 | ) | ||||
Other assets and liabilities | 104 | 34 | ||||||
|
|
|
| |||||
Net cash flows provided by operating activities | 1,749 | 1,346 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (1,950 | ) | (1,670 | ) | ||||
Change in restricted cash | — | 2 | ||||||
Other investing activities | 31 | 22 | ||||||
|
|
|
| |||||
Net cash flows used in investing activities | (1,919 | ) | (1,646 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Changes in short-term borrowings | (284 | ) | 300 | |||||
Issuance of long-term debt | 1,200 | 400 | ||||||
Retirement of long-term debt | (665 | ) | (260 | ) | ||||
Contributions from parent | 188 | 75 | ||||||
Dividends paid on common stock | (275 | ) | (226 | ) | ||||
Other financing activities | (17 | ) | (4 | ) | ||||
|
|
|
| |||||
Net cash flows provided by financing activities | 147 | 285 | ||||||
|
|
|
| |||||
Decrease in cash and cash equivalents | (23 | ) | (15 | ) | ||||
Cash and cash equivalents at beginning of period | 67 | 66 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 44 | $ | 51 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | ||||||
(Unaudited) | ||||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 44 | $ | 67 | ||||
Restricted cash | 2 | 2 | ||||||
Accounts receivable, net | ||||||||
Customer | 546 | 533 | ||||||
Other | 259 | 272 | ||||||
Receivables from affiliates | 359 | 199 | ||||||
Inventories, net | 156 | 164 | ||||||
Regulatory assets | 205 | 218 | ||||||
Other | 63 | 63 | ||||||
|
|
|
| |||||
Total current assets | 1,634 | 1,518 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 18,811 | 17,502 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 987 | 895 | ||||||
Investments | 6 | 6 | ||||||
Goodwill | 2,625 | 2,625 | ||||||
Receivables from affiliates | 2,238 | 2,172 | ||||||
Prepaid pension asset | 1,387 | 1,490 | ||||||
Other | 332 | 324 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 7,575 | 7,512 | ||||||
|
|
|
| |||||
Total assets | $ | 28,020 | $ | 26,532 | ||||
|
|
|
|
Three Months Ended March 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 141 | $ | 115 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation and amortization | 208 | 189 | ||||||
Deferred income taxes and amortization of investment tax credits | 137 | 70 | ||||||
Othernon-cash operating activities | 31 | 32 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | 92 | 69 | ||||||
Receivables from and payables to affiliates, net | (16 | ) | — | |||||
Inventories | 4 | 7 | ||||||
Accounts payable and accrued expenses | (327 | ) | (207 | ) | ||||
Collateral (posted) received, net | (7 | ) | 7 | |||||
Income taxes | (34 | ) | 20 | |||||
Pension andnon-pension postretirement benefit contributions | (35 | ) | (32 | ) | ||||
Other assets and liabilities | (49 | ) | 14 | |||||
|
|
|
| |||||
Net cash flows provided by operating activities | 145 | 284 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (535 | ) | (639 | ) | ||||
Change in restricted cash | (1 | ) | — | |||||
Other investing activities | 7 | 13 | ||||||
|
|
|
| |||||
Net cash flows used in investing activities | (529 | ) | (626 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Changes in short-term borrowings | 365 | 349 | ||||||
Contributions from parent | 100 | 39 | ||||||
Dividends paid on common stock | (105 | ) | (91 | ) | ||||
Other financing activities | (1 | ) | (1 | ) | ||||
|
|
|
| |||||
Net cash flows provided by financing activities | 359 | 296 | ||||||
|
|
|
| |||||
Decrease in cash and cash equivalents | (25 | ) | (46 | ) | ||||
Cash and cash equivalents at beginning of period | 56 | 67 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 31 | $ | 21 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | ||||||
(Unaudited) | ||||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
Short-term borrowings | $ | 10 | $ | 294 | ||||
Long-term debt due within one year | 425 | 665 | ||||||
Accounts payable | 625 | 660 | ||||||
Accrued expenses | 1,045 | 706 | ||||||
Payables to affiliates | 57 | 62 | ||||||
Customer deposits | 126 | 131 | ||||||
Regulatory liabilities | 204 | 155 | ||||||
Mark-to-market derivative liability | 19 | 23 | ||||||
Other | 78 | 70 | ||||||
|
|
|
| |||||
Total current liabilities | 2,589 | 2,766 | ||||||
|
|
|
| |||||
Long-term debt | 6,606 | 5,844 | ||||||
Long-term debt to financing trust | 205 | 205 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 5,320 | 4,914 | ||||||
Asset retirement obligations | 118 | 111 | ||||||
Non-pension postretirement benefits obligations | 244 | 259 | ||||||
Regulatory liabilities | 3,577 | 3,459 | ||||||
Mark-to-market derivative liability | 225 | 224 | ||||||
Other | 526 | 507 | ||||||
|
|
|
| |||||
Total deferred credits and other liabilities | 10,010 | 9,474 | ||||||
|
|
|
| |||||
Total liabilities | 19,410 | 18,289 | ||||||
|
|
|
| |||||
Commitments and contingencies | ||||||||
Shareholders’ equity | ||||||||
Common stock | 1,588 | 1,588 | ||||||
Other paid-in capital | 6,022 | 5,677 | ||||||
Retained earnings | 1,000 | 978 | ||||||
|
|
|
| |||||
Total shareholders’ equity | 8,610 | 8,243 | ||||||
|
|
|
| |||||
Total liabilities and shareholders’ equity | $ | 28,020 | $ | 26,532 | ||||
|
|
|
|
(In millions) | March 31, 2017 | December 31, 2016 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 31 | $ | 56 | ||||
Restricted cash | 3 | 2 | ||||||
Accounts receivable, net | ||||||||
Customer | 461 | 528 | ||||||
Other | 199 | 218 | ||||||
Receivables from affiliates | 360 | 356 | ||||||
Inventories, net | 154 | 159 | ||||||
Regulatory assets | 183 | 190 | ||||||
Other | 55 | 45 | ||||||
|
|
|
| |||||
Total current assets | 1,446 | 1,554 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 19,692 | 19,335 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 1,032 | 977 | ||||||
Investments | 6 | 6 | ||||||
Goodwill | 2,625 | 2,625 | ||||||
Receivables from affiliates | 2,294 | 2,170 | ||||||
Prepaid pension asset | 1,330 | 1,343 | ||||||
Other | 331 | 325 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 7,618 | 7,446 | ||||||
|
|
|
| |||||
Total assets | $ | 28,756 | $ | 28,335 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITYBALANCE SHEETS
(Unaudited)
(In millions) | Common Stock | Other Paid-In Capital | Retained Deficit Unappropriated | Retained Earnings Appropriated | Total Shareholders’ Equity | |||||||||||||||
Balance, December 31, 2015 | $ | 1,588 | $ | 5,677 | $ | (1,639 | ) | $ | 2,617 | $ | 8,243 | |||||||||
Net income | — | — | 297 | — | 297 | |||||||||||||||
Appropriation of retained earnings for future dividends | — | — | (297 | ) | 297 | — | ||||||||||||||
Common stock dividends | — | — | — | (275 | ) | (275 | ) | |||||||||||||
Contribution from parent | — | 188 | — | — | 188 | |||||||||||||||
Parent tax matter indemnification | — | 157 | — | — | 157 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Balance, September 30, 2016 | $ | 1,588 | $ | 6,022 | $ | (1,639 | ) | $ | 2,639 | $ | 8,610 | |||||||||
|
|
|
|
|
|
|
|
|
|
(In millions) | March 31, 2017 | December 31, 2016 | ||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
Short-term borrowings | $ | 365 | $ | — | ||||
Long-term debt due within one year | 1,125 | 425 | ||||||
Accounts payable | 518 | 645 | ||||||
Accrued expenses | 1,061 | 1,250 | ||||||
Payables to affiliates | 52 | 65 | ||||||
Customer deposits | 117 | 121 | ||||||
Regulatory liabilities | 311 | 329 | ||||||
Mark-to-market derivative liability | 19 | 19 | ||||||
Other | 77 | 84 | ||||||
|
|
|
| |||||
Total current liabilities | 3,645 | 2,938 | ||||||
|
|
|
| |||||
Long-term debt | 5,910 | 6,608 | ||||||
Long-term debt to financing trust | 205 | 205 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 5,502 | 5,364 | ||||||
Asset retirement obligations | 121 | 119 | ||||||
Non-pension postretirement benefits obligations | 234 | 239 | ||||||
Regulatory liabilities | 3,492 | 3,369 | ||||||
Mark-to-market derivative liability | 263 | 239 | ||||||
Other | 523 | 529 | ||||||
|
|
|
| |||||
Total deferred credits and other liabilities | 10,135 | 9,859 | ||||||
|
|
|
| |||||
Total liabilities | 19,895 | 19,610 | ||||||
|
|
|
| |||||
Commitments and contingencies | ||||||||
Shareholders’ equity | ||||||||
Common stock | 1,588 | 1,588 | ||||||
Otherpaid-in capital | 6,250 | 6,150 | ||||||
Retained deficit unappropriated | (1,639 | ) | (1,639 | ) | ||||
Retained earnings appropriated | 2,662 | 2,626 | ||||||
|
|
|
| |||||
Total shareholders’ equity | 8,861 | 8,725 | ||||||
|
|
|
| |||||
Total liabilities and shareholders’ equity | $ | 28,756 | $ | 28,335 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
(In millions) | Common Stock | Other Paid-In Capital | Retained Deficit Unappropriated | Retained Earnings Appropriated | Total Shareholders’ Equity | |||||||||||||||
Balance, December 31, 2016 | $ | 1,588 | $ | 6,150 | $ | (1,639 | ) | $ | 2,626 | $ | 8,725 | |||||||||
Net income | — | — | 141 | — | 141 | |||||||||||||||
Appropriation of retained earnings for future dividends | — | — | (141 | ) | 141 | — | ||||||||||||||
Common stock dividends | — | — | — | (105 | ) | (105 | ) | |||||||||||||
Contribution from parent | — | 100 | — | — | 100 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Balance, March 31, 2017 | $ | 1,588 | $ | 6,250 | $ | (1,639 | ) | $ | 2,662 | $ | 8,861 | |||||||||
|
|
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
(In millions) | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||
Operating revenues | ||||||||||||||||||||||||
Electric operating revenues | $ | 738 | $ | 691 | $ | 1,966 | $ | 1,950 | $ | 589 | $ | 643 | ||||||||||||
Natural gas operating revenues | 48 | 48 | 322 | 435 | 206 | 197 | ||||||||||||||||||
Operating revenues from affiliates | 2 | 1 | 5 | 1 | 1 | 1 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total operating revenues | 788 | 740 | 2,293 | 2,386 | 796 | 841 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||
Purchased power | 171 | 207 | 466 | 584 | 156 | 166 | ||||||||||||||||||
Purchased fuel | 10 | 10 | 110 | 198 | 86 | 77 | ||||||||||||||||||
Purchased power from affiliate | 91 | 61 | 233 | 171 | 45 | 78 | ||||||||||||||||||
Operating and maintenance | 168 | 166 | 501 | 529 | 174 | 177 | ||||||||||||||||||
Operating and maintenance from affiliates | 31 | 30 | 103 | 80 | 34 | 38 | ||||||||||||||||||
Depreciation and amortization | 67 | 68 | 201 | 198 | 71 | 67 | ||||||||||||||||||
Taxes other than income | 46 | 44 | 126 | 125 | 38 | 42 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total operating expenses | 584 | 586 | 1,740 | 1,885 | 604 | 645 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Gain on sales of assets | — | — | — | 1 | ||||||||||||||||||||
|
|
|
| |||||||||||||||||||||
Operating income | 204 | 154 | 553 | 502 | 192 | 196 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Other income and (deductions) | ||||||||||||||||||||||||
Interest expense, net | (27 | ) | (25 | ) | (83 | ) | (75 | ) | (28 | ) | (28 | ) | ||||||||||||
Interest expense to affiliates | (3 | ) | (3 | ) | (9 | ) | (9 | ) | (3 | ) | (3 | ) | ||||||||||||
Other, net | 2 | 1 | 6 | 3 | 2 | 2 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total other income and (deductions) | (28 | ) | (27 | ) | (86 | ) | (81 | ) | (29 | ) | (29 | ) | ||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Income before income taxes | 176 | 127 | 467 | 421 | 163 | 167 | ||||||||||||||||||
Income taxes | 54 | 37 | 121 | 122 | 36 | 43 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Net income attributable to common shareholder | $ | 122 | $ | 90 | $ | 346 | $ | 299 | ||||||||||||||||
Net income | $ | 127 | $ | 124 | ||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Comprehensive income | $ | 122 | $ | 90 | $ | 346 | $ | 299 | $ | 127 | $ | 124 | ||||||||||||
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||
(In millions) | 2016 | 2015 | 2017 | 2016 | ||||||||||||
Cash flows from operating activities | ||||||||||||||||
Net income | $ | 346 | $ | 299 | $ | 127 | $ | 124 | ||||||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||||||||||
Depreciation, amortization and accretion | 201 | 198 | ||||||||||||||
Depreciation and amortization | 71 | 67 | ||||||||||||||
Deferred income taxes and amortization of investment tax credits | 69 | 11 | 24 | 23 | ||||||||||||
Other non-cash operating activities | 49 | 69 | 23 | 24 | ||||||||||||
Changes in assets and liabilities: | ||||||||||||||||
Accounts receivable | (50 | ) | (15 | ) | (25 | ) | (51 | ) | ||||||||
Receivables from and payables to affiliates, net | 9 | — | (10 | ) | 4 | |||||||||||
Inventories | 5 | 8 | 19 | 24 | ||||||||||||
Accounts payable and accrued expenses | (12 | ) | (19 | ) | (82 | ) | 18 | |||||||||
Income taxes | 43 | 69 | 25 | 29 | ||||||||||||
Pension and non-pension postretirement benefit contributions | (29 | ) | (37 | ) | (23 | ) | (29 | ) | ||||||||
Other assets and liabilities | (49 | ) | (16 | ) | (85 | ) | (95 | ) | ||||||||
|
|
|
| |||||||||||||
Net cash flows provided by operating activities | 582 | 567 | 64 | 138 | ||||||||||||
|
|
|
| |||||||||||||
Cash flows from investing activities | ||||||||||||||||
Capital expenditures | (448 | ) | (435 | ) | (159 | ) | (195 | ) | ||||||||
Change in restricted cash | — | (1 | ) | |||||||||||||
Changes in Exelon intercompany money pool | 131 | (160 | ) | |||||||||||||
Other investing activities | 10 | 11 | 1 | 4 | ||||||||||||
|
|
|
| |||||||||||||
Net cash flows used in investing activities | (438 | ) | (425 | ) | (27 | ) | (351 | ) | ||||||||
|
|
|
| |||||||||||||
Cash flows from financing activities | ||||||||||||||||
Issuance of long-term debt | 300 | — | ||||||||||||||
Restricted proceeds from issuance of long-term debt | (30 | ) | — | |||||||||||||
Changes in Exelon intercompany money pool | — | 55 | ||||||||||||||
Contributions from parent | 18 | 16 | ||||||||||||||
Dividends paid on common stock | (208 | ) | (209 | ) | (72 | ) | (69 | ) | ||||||||
Other financing activities | (3 | ) | (2 | ) | ||||||||||||
|
|
|
| |||||||||||||
Net cash flows provided by (used in) financing activities | 77 | (140 | ) | |||||||||||||
Net cash flows used in financing activities | (72 | ) | (69 | ) | ||||||||||||
|
|
|
| |||||||||||||
Increase in cash and cash equivalents | 221 | 2 | ||||||||||||||
Decrease in cash and cash equivalents | (35 | ) | (282 | ) | ||||||||||||
Cash and cash equivalents at beginning of period | 295 | 30 | 63 | 295 | ||||||||||||
|
|
|
| |||||||||||||
Cash and cash equivalents at end of period | $ | 516 | $ | 32 | $ | 28 | $ | 13 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | ||||||||||||
(Unaudited) | ||||||||||||||||
ASSETS | ||||||||||||||||
Current assets | ||||||||||||||||
Cash and cash equivalents | $ | 516 | $ | 295 | $ | 28 | $ | 63 | ||||||||
Restricted cash and cash equivalents | 33 | 3 | 4 | 4 | ||||||||||||
Accounts receivable, net | ||||||||||||||||
Customer | 271 | 258 | 314 | 306 | ||||||||||||
Other | 132 | 146 | 122 | 131 | ||||||||||||
Receivables from affiliates | 3 | 2 | 6 | 4 | ||||||||||||
Receivable from Exelon intercompany pool | — | 131 | ||||||||||||||
Inventories, net | ||||||||||||||||
Fossil fuel | 38 | 43 | 14 | 35 | ||||||||||||
Materials and supplies | 26 | 26 | 29 | 27 | ||||||||||||
Prepaid utility taxes | 43 | 11 | 100 | 9 | ||||||||||||
Regulatory assets | 37 | 34 | 40 | 29 | ||||||||||||
Other | 22 | 24 | 21 | 18 | ||||||||||||
|
|
|
| |||||||||||||
Total current assets | 1,121 | 842 | 678 | 757 | ||||||||||||
|
|
|
| |||||||||||||
Property, plant and equipment, net | 7,400 | 7,141 | 7,659 | 7,565 | ||||||||||||
Deferred debits and other assets | ||||||||||||||||
Regulatory assets | 1,651 | 1,583 | 1,708 | 1,681 | ||||||||||||
Investments | 26 | 28 | 25 | 25 | ||||||||||||
Receivable from affiliates | 466 | 405 | 482 | 438 | ||||||||||||
Prepaid pension asset | 353 | 347 | 361 | 345 | ||||||||||||
Other | 24 | 21 | 19 | 20 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred debits and other assets | 2,520 | 2,384 | 2,595 | 2,509 | ||||||||||||
|
|
|
| |||||||||||||
Total assets | $ | 11,041 | $ | 10,367 | $ | 10,932 | $ | 10,831 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | ||||||||||||
(Unaudited) | ||||||||||||||||
LIABILITIES AND SHAREHOLDER’S EQUITY | ||||||||||||||||
Current liabilities | ||||||||||||||||
Long-term debt due within one year | $ | 300 | $ | 300 | $ | 500 | $ | — | ||||||||
Accounts payable | 282 | 281 | 288 | 342 | ||||||||||||
Accrued expenses | 108 | 109 | 92 | 104 | ||||||||||||
Payables to affiliates | 64 | 55 | 55 | 63 | ||||||||||||
Customer deposits | 60 | 58 | 62 | 61 | ||||||||||||
Regulatory liabilities | 128 | 112 | 161 | 127 | ||||||||||||
Other | 26 | 29 | 29 | 30 | ||||||||||||
|
|
|
| |||||||||||||
Total current liabilities | 968 | 944 | 1,187 | 727 | ||||||||||||
|
|
|
| |||||||||||||
Long-term debt | 2,579 | 2,280 | 2,080 | 2,580 | ||||||||||||
Long-term debt to financing trusts | 184 | 184 | 184 | 184 | ||||||||||||
Deferred credits and other liabilities | ||||||||||||||||
Deferred income taxes and unamortized investment tax credits | 2,964 | 2,792 | 3,076 | 3,006 | ||||||||||||
Asset retirement obligations | 28 | 27 | 28 | 28 | ||||||||||||
Non-pension postretirement benefits obligations | 288 | 287 | 289 | 289 | ||||||||||||
Regulatory liabilities | 551 | 527 | 530 | 517 | ||||||||||||
Other | 87 | 90 | 88 | 85 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred credits and other liabilities | 3,918 | 3,723 | 4,011 | 3,925 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities | 7,649 | 7,131 | 7,462 | 7,416 | ||||||||||||
|
|
|
| |||||||||||||
Commitments and contingencies | ||||||||||||||||
Shareholder’s equity | ||||||||||||||||
Common stock | 2,473 | 2,455 | 2,473 | 2,473 | ||||||||||||
Retained earnings | 918 | 780 | 996 | 941 | ||||||||||||
Accumulated other comprehensive income, net | 1 | 1 | 1 | 1 | ||||||||||||
|
|
|
| |||||||||||||
Total shareholder’s equity | 3,392 | 3,236 | 3,470 | 3,415 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities and shareholder’s equity | $ | 11,041 | $ | 10,367 | $ | 10,932 | $ | 10,831 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
(In millions) | Common Stock | Retained Earnings | Accumulated Other Comprehensive Income, net | Total Shareholder’s Equity | Common Stock | Retained Earnings | Accumulated Other Comprehensive Income, net | Total Shareholder’s Equity | ||||||||||||||||||||||||
Balance, December 31, 2015 | $ | 2,455 | $ | 780 | $ | 1 | $ | 3,236 | ||||||||||||||||||||||||
Balance, December 31, 2016 | $ | 2,473 | $ | 941 | $ | 1 | $ | 3,415 | ||||||||||||||||||||||||
Net income | — | 346 | — | 346 | — | 127 | — | 127 | ||||||||||||||||||||||||
Common stock dividends | — | (208 | ) | — | (208 | ) | — | (72 | ) | — | (72 | ) | ||||||||||||||||||||
Allocation of tax benefit from parent | 18 | — | — | 18 | ||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Balance, September 30, 2016 | $ | 2,473 | $ | 918 | $ | 1 | $ | 3,392 | ||||||||||||||||||||||||
Balance, March 31, 2017 | $ | 2,473 | $ | 996 | $ | 1 | $ | 3,470 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
(In millions) | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||
Operating revenues | ||||||||||||||||||||||||
Electric operating revenues | $ | 733 | $ | 656 | $ | 1,993 | $ | 1,910 | $ | 665 | $ | 678 | ||||||||||||
Natural gas operating revenues | 72 | 66 | 412 | 468 | 281 | 246 | ||||||||||||||||||
Operating revenues from affiliates | 7 | 3 | 16 | 10 | 5 | 5 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total operating revenues | 812 | 725 | 2,421 | 2,388 | 951 | 929 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||
Purchased power | 164 | 159 | 399 | 497 | 133 | 127 | ||||||||||||||||||
Purchased fuel | 14 | 11 | 109 | 167 | 83 | 75 | ||||||||||||||||||
Purchased power from affiliate | 182 | 141 | 486 | 373 | 134 | 171 | ||||||||||||||||||
Operating and maintenance | 150 | 138 | 494 | 412 | 148 | 168 | ||||||||||||||||||
Operating and maintenance from affiliates | 28 | 31 | 94 | 87 | 35 | 34 | ||||||||||||||||||
Depreciation and amortization | 101 | 79 | 307 | 271 | 128 | 109 | ||||||||||||||||||
Taxes other than income | 58 | 57 | 172 | 169 | 62 | 58 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total operating expenses | 697 | 616 | 2,061 | 1,976 | 723 | 742 | ||||||||||||||||||
|
|
|
| |||||||||||||||||||||
Gain on sale of assets | — | 1 | — | 1 | ||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Operating income | 115 | 110 | 360 | 413 | 228 | 187 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Other income and (deductions) | ||||||||||||||||||||||||
Interest expense, net | (24 | ) | (21 | ) | (64 | ) | (62 | ) | (23 | ) | (20 | ) | ||||||||||||
Interest expense to affiliates | (4 | ) | (4 | ) | (12 | ) | (11 | ) | (4 | ) | (4 | ) | ||||||||||||
Other, net | 5 | 4 | 16 | 13 | 4 | 4 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total other income and (deductions) | (23 | ) | (21 | ) | (60 | ) | (60 | ) | (23 | ) | (20 | ) | ||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Income before income taxes | 92 | 89 | 300 | 353 | 205 | 167 | ||||||||||||||||||
Income taxes | 36 | 35 | 109 | 141 | 80 | 66 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Net income | 56 | 54 | 191 | 212 | 125 | 101 | ||||||||||||||||||
Preference stock dividends | 2 | 3 | 8 | 10 | — | 3 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Net income attributable to common shareholder | $ | 54 | $ | 51 | $ | 183 | $ | 202 | $ | 125 | $ | 98 | ||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Comprehensive income | $ | 56 | $ | 54 | $ | 191 | $ | 212 | $ | 125 | $ | 101 | ||||||||||||
Comprehensive income attributable to preference stock dividends | 2 | 3 | 8 | 10 | — | 3 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Comprehensive income attributable to common shareholder | $ | 54 | $ | 51 | $ | 183 | $ | 202 | $ | 125 | $ | 98 | ||||||||||||
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30, | ||||||||
(In millions) | 2016 | 2015 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 191 | $ | 212 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation, amortization and accretion | 307 | 271 | ||||||
Impairment of long-lived assets and losses on regulatory assets | 52 | — | ||||||
Deferred income taxes and amortization of investment tax credits | 54 | 79 | ||||||
Other non-cash operating activities | 109 | 111 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (50 | ) | 62 | |||||
Receivables from and payables to affiliates, net | (10 | ) | (8 | ) | ||||
Inventories | (7 | ) | 10 | |||||
Accounts payable and accrued expenses | 43 | 34 | ||||||
Collateral posted, net | — | (27 | ) | |||||
Income taxes | 19 | (6 | ) | |||||
Pension and non-pension postretirement benefit contributions | (46 | ) | (14 | ) | ||||
Other assets and liabilities | (2 | ) | (28 | ) | ||||
|
|
|
| |||||
Net cash flows provided by operating activities | 660 | 696 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (611 | ) | (506 | ) | ||||
Change in restricted cash | (22 | ) | 2 | |||||
Other investing activities | 19 | 13 | ||||||
|
|
|
| |||||
Net cash flows used in investing activities | (614 | ) | (491 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Changes in short-term borrowings | (210 | ) | (70 | ) | ||||
Issuance of long-term debt | 850 | — | ||||||
Retirement of long-term debt | (39 | ) | (37 | ) | ||||
Redemption of preference stock | (190 | ) | — | |||||
Dividends paid on preference stock | (8 | ) | (10 | ) | ||||
Dividends paid on common stock | (134 | ) | (116 | ) | ||||
Contributions from parent | 28 | 6 | ||||||
Other financing activities | (11 | ) | (15 | ) | ||||
|
|
|
| |||||
Net cash flows provided by (used in) financing activities | 286 | (242 | ) | |||||
|
|
|
| |||||
Increase (Decrease) in cash and cash equivalents | 332 | (37 | ) | |||||
Cash and cash equivalents at beginning of period | 9 | 64 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 341 | $ | 27 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
(Unaudited)
Three Months Ended March 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 125 | $ | 101 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation and amortization | 128 | 109 | ||||||
Deferred income taxes and amortization of investment tax credits | 72 | 26 | ||||||
Othernon-cash operating activities | 24 | 44 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (7 | ) | (44 | ) | ||||
Receivables from and payables to affiliates, net | (7 | ) | 7 | |||||
Inventories | 17 | 17 | ||||||
Accounts payable and accrued expenses | (121 | ) | 3 | |||||
Income taxes | 33 | 78 | ||||||
Pension andnon-pension postretirement benefit contributions | (44 | ) | (38 | ) | ||||
Other assets and liabilities | (52 | ) | (30 | ) | ||||
|
|
|
| |||||
Net cash flows provided by operating activities | 168 | 273 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (166 | ) | (176 | ) | ||||
Change in restricted cash | (19 | ) | (20 | ) | ||||
Other investing activities | 4 | 5 | ||||||
|
|
|
| |||||
Net cash flows used in investing activities | (181 | ) | (191 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Changes in short-term borrowings | 50 | (60 | ) | |||||
Dividends paid on preference stock | — | (3 | ) | |||||
Dividends paid on common stock | (49 | ) | (45 | ) | ||||
Contributions from parent | — | 21 | ||||||
Other financing activities | — | 1 | ||||||
|
|
|
| |||||
Net cash flows provided by (used in) financing activities | 1 | (86 | ) | |||||
|
|
|
| |||||
Decrease in cash and cash equivalents | (12 | ) | (4 | ) | ||||
Cash and cash equivalents at beginning of period | 23 | 9 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 11 | $ | 5 | ||||
|
|
|
|
(In millions) | September 30, 2016 | December 31, 2015 | ||||||
(Unaudited) | ||||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 341 | $ | 9 | ||||
Restricted cash and cash equivalents | 46 | 24 | ||||||
Accounts receivable, net | ||||||||
Customer | 332 | 300 | ||||||
Other | 100 | 112 | ||||||
Inventories, net | ||||||||
Gas held in storage | 37 | 36 | ||||||
Materials and supplies | 39 | 33 | ||||||
Prepaid utility taxes | — | 61 | ||||||
Regulatory assets | 214 | 267 | ||||||
Other | 5 | 3 | ||||||
|
|
|
| |||||
Total current assets | 1,114 | 845 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 6,904 | 6,597 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 508 | 514 | ||||||
Investments | 12 | 12 | ||||||
Prepaid pension asset | 310 | 319 | ||||||
Other | 9 | 8 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 839 | 853 | ||||||
|
|
|
| |||||
Total assets(a) | $ | 8,857 | $ | 8,295 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | ||||||
(Unaudited) | ||||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
Short-term borrowings | $ | — | $ | 210 | ||||
Long-term debt due within one year | 381 | 378 | ||||||
Accounts payable | 239 | 209 | ||||||
Accrued expenses | 144 | 110 | ||||||
Payables to affiliates | 42 | 52 | ||||||
Customer deposits | 108 | 102 | ||||||
Regulatory liabilities | 54 | 38 | ||||||
Other | 35 | 35 | ||||||
|
|
|
| |||||
Total current liabilities | 1,003 | 1,134 | ||||||
|
|
|
| |||||
Long-term debt | 2,281 | 1,480 | ||||||
Long-term debt to financing trust | 252 | 252 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 2,149 | 2,081 | ||||||
Asset retirement obligations | 21 | 17 | ||||||
Non-pension postretirement benefits obligations | 204 | 209 | ||||||
Regulatory liabilities | 118 | 184 | ||||||
Other | 72 | 61 | ||||||
|
|
|
| |||||
Total deferred credits and other liabilities | 2,564 | 2,552 | ||||||
|
|
|
| |||||
Total liabilities(a) | 6,100 | 5,418 | ||||||
|
|
|
| |||||
Commitments and contingencies | ||||||||
Shareholders’ equity | ||||||||
Common stock | 1,388 | 1,367 | ||||||
Retained earnings | 1,369 | 1,320 | ||||||
|
|
|
| |||||
Total shareholders’ equity | 2,757 | 2,687 | ||||||
|
|
|
| |||||
Preference stock not subject to mandatory redemption | — | 190 | ||||||
|
|
|
| |||||
Total equity | 2,757 | 2,877 | ||||||
|
|
|
| |||||
Total liabilities and shareholders’ equity | $ | 8,857 | $ | 8,295 | ||||
|
|
|
|
(In millions) | March 31, 2017 | December 31, 2016 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 11 | $ | 23 | ||||
Restricted cash and cash equivalents | 43 | 24 | ||||||
Accounts receivable, net | ||||||||
Customer | 393 | 395 | ||||||
Other | 79 | 102 | ||||||
Receivables from affiliates | 1 | — | ||||||
Inventories, net | ||||||||
Gas held in storage | 10 | 30 | ||||||
Materials and supplies | 41 | 38 | ||||||
Prepaid utility taxes | 32 | 15 | ||||||
Regulatory assets | 191 | 208 | ||||||
Other | 11 | 7 | ||||||
|
|
|
| |||||
Total current assets | 812 | 842 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 7,166 | 7,040 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 499 | 504 | ||||||
Investments | 12 | 12 | ||||||
Prepaid pension asset | 322 | 297 | ||||||
Other | 10 | 9 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 843 | 822 | ||||||
|
|
|
| |||||
Total assets(a) | $ | 8,821 | $ | 8,704 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions) | March 31, 2017 | December 31, 2016 | ||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
Short-term borrowings | $ | 95 | $ | 45 | ||||
Long-term debt due within one year | 41 | 41 | ||||||
Accounts payable | 186 | 205 | ||||||
Accrued expenses | 120 | 175 | ||||||
Payables to affiliates | 49 | 55 | ||||||
Customer deposits | 112 | 110 | ||||||
Regulatory liabilities | 67 | 50 | ||||||
Other | 23 | 26 | ||||||
|
|
|
| |||||
Total current liabilities | 693 | 707 | ||||||
|
|
|
| |||||
Long-term debt | 2,282 | 2,281 | ||||||
Long-term debt to financing trust | 252 | 252 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes and unamortized investment tax credits | 2,295 | 2,219 | ||||||
Asset retirement obligations | 20 | 21 | ||||||
Non-pension postretirement benefits obligations | 202 | 205 | ||||||
Regulatory liabilities | 94 | 110 | ||||||
Other | 59 | 61 | ||||||
|
|
|
| |||||
Total deferred credits and other liabilities | 2,670 | 2,616 | ||||||
|
|
|
| |||||
Total liabilities(a) | 5,897 | 5,856 | ||||||
|
|
|
| |||||
Commitments and contingencies | ||||||||
Shareholders’ equity | ||||||||
Common stock | 1,421 | 1,421 | ||||||
Retained earnings | 1,503 | 1,427 | ||||||
|
|
|
| |||||
Total shareholders’ equity | 2,924 | 2,848 | ||||||
|
|
|
| |||||
Total liabilities and shareholders’ equity | $ | 8,821 | $ | 8,704 | ||||
|
|
|
|
(a) | BGE’s consolidated assets include |
See the Combined Notes to Consolidated Financial Statements
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
(In millions) | Common Stock | Retained Earnings | Total Shareholders’ Equity | Preference Stock Not Subject To Mandatory Redemption | Total Equity | |||||||||||||||
Balance, December 31, 2015 | $ | 1,367 | $ | 1,320 | $ | 2,687 | $ | 190 | $ | 2,877 | ||||||||||
Net income | — | 191 | 191 | — | 191 | |||||||||||||||
Preference stock dividends | — | (8 | ) | (8 | ) | — | (8 | ) | ||||||||||||
Common stock dividends | — | (134 | ) | (134 | ) | — | (134 | ) | ||||||||||||
Distribution to parent | (7 | ) | — | (7 | ) | — | (7 | ) | ||||||||||||
Contribution from parent | 28 | — | 28 | — | 28 | |||||||||||||||
Redemption of preference stock | — | — | — | (190 | ) | (190 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Balance, September 30, 2016 | $ | 1,388 | $ | 1,369 | $ | 2,757 | $ | — | $ | 2,757 | ||||||||||
|
|
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
(In millions) | Common Stock | Retained Earnings | Total Shareholders’ Equity | |||||||||
Balance, December 31, 2016 | $ | 1,421 | $ | 1,427 | $ | 2,848 | ||||||
Net income | — | 125 | 125 | |||||||||
Common stock dividends | — | (49 | ) | (49 | ) | |||||||
|
|
|
|
|
| |||||||
Balance, March 31, 2017 | $ | 1,421 | $ | 1,503 | $ | 2,924 | ||||||
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Successor | Predecessor | Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | March 24 to September 30, | January 1 to March 23, | Nine Months Ended September 30, | Three Months Ended March 31, | March 24 to March 31, | January 1 to March 23, | |||||||||||||||||||||||||||||||||||||||||||||||||
(In millions) | 2016 | 2015 | 2016 | 2016 | 2015 | 2017 | 2016 | 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||
Operating revenues | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric operating revenues | $ | 1,366 | $ | 1,317 | $ | 2,485 | $ | 1,096 | $ | 3,680 | $ | 1,097 | $ | 90 | $ | 1,096 | ||||||||||||||||||||||||||||||||||||||||
Natural gas operating revenues | 17 | 19 | 46 | 57 | 129 | 66 | 3 | 57 | ||||||||||||||||||||||||||||||||||||||||||||||||
Operating revenues from affiliates | 11 | — | 34 | — | — | 12 | 12 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||||
Total operating revenues | 1,394 | 1,336 | 2,565 | 1,153 | 3,809 | 1,175 | 105 | 1,153 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased power | 370 | 570 | 658 | 471 | 1,575 | 288 | 26 | 471 | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchased fuel | 6 | 9 | 17 | 26 | 71 | 29 | 1 | 26 | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchased power and fuel from affiliates | 207 | — | 362 | — | — | 144 | 11 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Operating and maintenance | 200 | 287 | 870 | 294 | 875 | 223 | 447 | 294 | ||||||||||||||||||||||||||||||||||||||||||||||||
Operating and maintenance from affiliates | 26 | — | 51 | — | — | 33 | 2 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Depreciation, amortization and accretion | 182 | 166 | 355 | 152 | 474 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Depreciation and amortization | 167 | 14 | 152 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Taxes other than income | 124 | 120 | 248 | 105 | 349 | 111 | 15 | 105 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||||
Total operating expenses | 1,115 | 1,152 | 2,561 | 1,048 | 3,344 | 995 | 516 | 1,048 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||||
Operating income | 279 | 184 | 4 | 105 | 465 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Operating income (loss) | 180 | (411 | ) | 105 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||||
Other income and (deductions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest expense, net | (64 | ) | (71 | ) | (135 | ) | (65 | ) | (211 | ) | (62 | ) | (6 | ) | (65 | ) | ||||||||||||||||||||||||||||||||||||||||
Other, net | 19 | 27 | 31 | (4 | ) | 48 | 13 | 2 | (4 | ) | ||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||||
Total other income and (deductions) | (45 | ) | (44 | ) | (104 | ) | (69 | ) | (163 | ) | (49 | ) | (4 | ) | (69 | ) | ||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||||
Income (loss) before income taxes | 234 | 140 | (100 | ) | 36 | 302 | 131 | (415 | ) | 36 | ||||||||||||||||||||||||||||||||||||||||||||||
Income taxes | 68 | 49 | (9 | ) | 17 | 105 | (9 | ) | (106 | ) | 17 | |||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||||
Net income (loss) attributable to membership interest/common shareholders | $ | 166 | $ | 91 | $ | (91 | ) | $ | 19 | $ | 197 | |||||||||||||||||||||||||||||||||||||||||||||
Net income (loss) | $ | 140 | $ | (309 | ) | $ | 19 | |||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||||
Comprehensive income (loss), net of income taxes | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net income (loss) | $ | 166 | $ | 91 | $ | (91 | ) | $ | 19 | $ | 197 | $ | 140 | $ | (309 | ) | $ | 19 | ||||||||||||||||||||||||||||||||||||||
Other comprehensive income, net of income taxes | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pension and non-pension postretirement benefit plans: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Actuarial loss reclassified to periodic cost | — | — | — | 1 | 4 | — | — | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||
Unrealized loss on cash flow hedges | — | 1 | — | — | 1 | |||||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||||
Other comprehensive income | — | 1 | — | 1 | 5 | — | — | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||||
Comprehensive income (loss) | $ | 166 | $ | 92 | $ | (91 | ) | $ | 20 | $ | 202 | $ | 140 | $ | (309 | ) | $ | 20 | ||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||||
March 24 to September 30, | January 1 to March 23, | Nine Months Ended September 30, | Three Months Ended March 31, | March 24 to March 31, | January 1 to March 23, | |||||||||||||||||||||||||||
(In millions) | 2016 | 2016 | 2015 | 2017 | 2016 | 2016 | ||||||||||||||||||||||||||
Cash flows from operating activities | ||||||||||||||||||||||||||||||||
Net (loss) income | $ | (91 | ) | $ | 19 | $ | 197 | |||||||||||||||||||||||||
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities: | ||||||||||||||||||||||||||||||||
Depreciation, amortization and accretion | 355 | 152 | 474 | |||||||||||||||||||||||||||||
Net income (loss) | $ | 140 | $ | (309 | ) | $ | 19 | |||||||||||||||||||||||||
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities: | ||||||||||||||||||||||||||||||||
Depreciation and amortization | 167 | 14 | 152 | |||||||||||||||||||||||||||||
Deferred income taxes and amortization of investment tax credits | 237 | 19 | 107 | 13 | (112 | ) | 19 | |||||||||||||||||||||||||
Net fair value changes related to derivatives | — | 18 | (15 | ) | — | — | 18 | |||||||||||||||||||||||||
Other non-cash operating activities | 441 | 46 | 143 | (8 | ) | 410 | 46 | |||||||||||||||||||||||||
Changes in assets and liabilities: | ||||||||||||||||||||||||||||||||
Accounts receivable | (94 | ) | (28 | ) | (211 | ) | 68 | 16 | (28 | ) | ||||||||||||||||||||||
Receivables from and payables to affiliates, net | 39 | — | — | (8 | ) | — | — | |||||||||||||||||||||||||
Inventories | — | (4 | ) | (5 | ) | (11 | ) | — | (4 | ) | ||||||||||||||||||||||
Accounts payable and accrued expenses | (23 | ) | 42 | 23 | (81 | ) | (4 | ) | 42 | |||||||||||||||||||||||
Collateral received, net | — | 1 | — | |||||||||||||||||||||||||||||
Income taxes | (57 | ) | 12 | 12 | 55 | 7 | 12 | |||||||||||||||||||||||||
Pension and non-pension postretirement benefit contributions | (13 | ) | (4 | ) | (12 | ) | (66 | ) | — | (4 | ) | |||||||||||||||||||||
Other assets and liabilities | (248 | ) | (9 | ) | (112 | ) | (75 | ) | (25 | ) | (8 | ) | ||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||
Net cash flows provided by operating activities | 546 | 264 | 601 | |||||||||||||||||||||||||||||
Net cash flows provided by (used in) operating activities | 194 | (3 | ) | 264 | ||||||||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||
Cash flows from investing activities | ||||||||||||||||||||||||||||||||
Capital expenditures | (624 | ) | (273 | ) | (855 | ) | (320 | ) | (29 | ) | (273 | ) | ||||||||||||||||||||
Proceeds from sales of long-lived assets | 19 | — | — | |||||||||||||||||||||||||||||
Changes in restricted cash | (39 | ) | 3 | 6 | 2 | (1 | ) | 3 | ||||||||||||||||||||||||
Purchases of investments | — | (68 | ) | — | — | (2 | ) | (68 | ) | |||||||||||||||||||||||
Other investing activities | 13 | (5 | ) | 14 | (3 | ) | 2 | (5 | ) | |||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||
Net cash flows used in investing activities | (631 | ) | (343 | ) | (835 | ) | (321 | ) | (30 | ) | (343 | ) | ||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||
Cash flows from financing activities | ||||||||||||||||||||||||||||||||
Changes in short-term borrowings | (520 | ) | (121 | ) | 99 | 145 | (20 | ) | (121 | ) | ||||||||||||||||||||||
Proceeds from short-term borrowings with maturities greater than 90 days | — | 500 | 300 | — | — | 500 | ||||||||||||||||||||||||||
Repayments of short-term borrowings with maturities greater than 90 days | (300 | ) | — | — | (500 | ) | — | — | ||||||||||||||||||||||||
Issuance of long-term debt | 2 | — | 408 | 1 | — | — | ||||||||||||||||||||||||||
Retirement of long-term debt | (29 | ) | (11 | ) | (163 | ) | (24 | ) | — | (11 | ) | |||||||||||||||||||||
Issuance of preferred stock | — | — | 54 | |||||||||||||||||||||||||||||
Dividends paid on common stock | — | — | (206 | ) | ||||||||||||||||||||||||||||
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation | — | 2 | 23 | — | — | 2 | ||||||||||||||||||||||||||
Distribution to member | (174 | ) | — | — | (69 | ) | (108 | ) | — | |||||||||||||||||||||||
Contribution from member | 1,088 | — | — | 500 | — | — | ||||||||||||||||||||||||||
Change in Exelon intercompany money pool | 1 | — | — | 13 | (7 | ) | — | |||||||||||||||||||||||||
Other financing activities | (3 | ) | 2 | (24 | ) | — | — | 2 | ||||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||
Net cash flows provided by financing activities | 65 | 372 | 491 | |||||||||||||||||||||||||||||
Net cash flows provided by (used in) financing activities | 66 | (135 | ) | 372 | ||||||||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||
(Decrease) Increase in cash and cash equivalents | (20 | ) | 293 | 257 | (61 | ) | (168 | ) | 293 | |||||||||||||||||||||||
Cash and cash equivalents at beginning of period | 319 | 26 | 15 | 170 | 319 | 26 | ||||||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||
Cash and cash equivalents at end of period | $ | 299 | $ | 319 | $ | 272 | $ | 109 | $ | 151 | $ | 319 | ||||||||||||||||||||
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
(Unaudited)
Successor | Predecessor | |||||||||||||||||||
September 30, 2016 | December 31, 2015 | Successor | ||||||||||||||||||
(In millions) | March 31, 2017 | December 31, 2016 | ||||||||||||||||||
ASSETS | ||||||||||||||||||||
Current assets | ||||||||||||||||||||
Cash and cash equivalents | $ | 299 | $ | 26 | $ | 109 | $ | 170 | ||||||||||||
Restricted cash and cash equivalents | 49 | 14 | 41 | 43 | ||||||||||||||||
Accounts receivable, net | ||||||||||||||||||||
Customer | 595 | 581 | 440 | 496 | ||||||||||||||||
Other | 345 | 319 | 210 | 283 | ||||||||||||||||
Mark-to-market derivative asset | — | 18 | ||||||||||||||||||
Inventories, net | ||||||||||||||||||||
Gas held in storage | 8 | 9 | 2 | 6 | ||||||||||||||||
Materials and supplies | 118 | 122 | 131 | 116 | ||||||||||||||||
Regulatory assets | 650 | 305 | 653 | 653 | ||||||||||||||||
Other | 54 | 80 | 64 | 71 | ||||||||||||||||
|
|
|
| |||||||||||||||||
Total current assets | 2,118 | 1,474 | 1,650 | 1,838 | ||||||||||||||||
|
|
|
| |||||||||||||||||
Property, plant and equipment, net | 11,311 | 10,864 | 11,801 | 11,598 | ||||||||||||||||
Deferred debits and other assets | ||||||||||||||||||||
Regulatory assets | 2,945 | 2,277 | 2,791 | 2,851 | ||||||||||||||||
Investments | 132 | 80 | 133 | 133 | ||||||||||||||||
Goodwill | 4,000 | 1,406 | 4,005 | 4,005 | ||||||||||||||||
Long-term note receivable | 4 | 4 | 4 | 4 | ||||||||||||||||
Prepaid pension asset | 470 | — | 549 | 509 | ||||||||||||||||
Deferred income taxes | 7 | 14 | 5 | 6 | ||||||||||||||||
Other | 76 | 69 | 80 | 81 | ||||||||||||||||
|
|
|
| |||||||||||||||||
Total deferred debits and other assets | 7,634 | 3,850 | 7,567 | 7,589 | ||||||||||||||||
|
|
|
| |||||||||||||||||
Total assets(a) | $ | 21,063 | $ | 16,188 | $ | 21,018 | $ | 21,025 | ||||||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
Successor | Predecessor | |||||||||||||||||||
September 30, 2016 | December 31, 2015 | Successor | ||||||||||||||||||
(In millions) | March 31, 2017 | December 31, 2016 | ||||||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||
LIABILITIES AND MEMBER’S EQUITY | ||||||||||||||||||||
Current liabilities | ||||||||||||||||||||
Short-term borrowings | $ | 517 | $ | 958 | $ | 167 | $ | 522 | ||||||||||||
Long-term debt due within one year | 545 | 456 | 241 | 253 | ||||||||||||||||
Accounts payable | 335 | 404 | 386 | 458 | ||||||||||||||||
Accrued expenses | 325 | 266 | 269 | 272 | ||||||||||||||||
Payables to affiliates | 90 | — | 84 | 94 | ||||||||||||||||
Unamortized energy contract liabilities | 376 | — | 320 | 335 | ||||||||||||||||
Borrowings from Exelon intercompany money pool | 7 | — | 13 | — | ||||||||||||||||
Customer deposits | 125 | 107 | 121 | 123 | ||||||||||||||||
Merger related obligation | 90 | — | 74 | 101 | ||||||||||||||||
Regulatory liabilities | 101 | 66 | 82 | 79 | ||||||||||||||||
Other | 36 | 70 | 43 | 47 | ||||||||||||||||
|
|
|
| |||||||||||||||||
Total current liabilities | 2,547 | 2,327 | 1,800 | 2,284 | ||||||||||||||||
|
|
|
| |||||||||||||||||
Long-term debt | 5,499 | 4,823 | 5,619 | 5,645 | ||||||||||||||||
Deferred credits and other liabilities | ||||||||||||||||||||
Regulatory liabilities | 167 | 147 | 154 | 158 | ||||||||||||||||
Deferred income taxes and unamortized investment tax credits | 3,746 | 3,406 | 3,789 | 3,775 | ||||||||||||||||
Asset retirement obligations | 14 | 8 | 14 | 14 | ||||||||||||||||
Pension obligations | — | 466 | ||||||||||||||||||
Non-pension postretirement benefit obligations | 139 | 215 | 129 | 134 | ||||||||||||||||
Unamortized energy contract liabilities | 830 | — | 701 | 750 | ||||||||||||||||
Other | 234 | 200 | 225 | 249 | ||||||||||||||||
|
|
|
| |||||||||||||||||
Total deferred credits and other liabilities | 5,130 | 4,442 | 5,012 | 5,080 | ||||||||||||||||
|
|
|
| |||||||||||||||||
Total liabilities(a) | 13,176 | 11,592 | 12,431 | 13,009 | ||||||||||||||||
|
|
|
| |||||||||||||||||
Commitments and contingencies | ||||||||||||||||||||
Preferred stock(b) | — | 183 | ||||||||||||||||||
Member’s equity | ||||||||||||||||||||
Membership interest | 8,577 | 8,077 | ||||||||||||||||||
Undistributed earnings (losses) | 10 | (61 | ) | |||||||||||||||||
|
|
|
| |||||||||||||||||
Member’s equity/Shareholders’ equity | ||||||||||||||||||||
Membership interest/Common stock(c) | 7,978 | 3,832 | ||||||||||||||||||
Undistributed (losses)/Retained earnings | (91 | ) | 617 | |||||||||||||||||
Accumulated other comprehensive loss, net | — | (36 | ) | |||||||||||||||||
Total member’s equity | 8,587 | 8,016 | ||||||||||||||||||
|
|
|
| |||||||||||||||||
Total member’s equity/shareholders’ equity | 7,887 | 4,413 | ||||||||||||||||||
Total liabilities and member’s equity | $ | 21,018 | $ | 21,025 | ||||||||||||||||
|
|
|
| |||||||||||||||||
Total liabilities and member’s equity/shareholders’ equity | $ | 21,063 | $ | 16,188 | ||||||||||||||||
|
|
(a) | PHI’s consolidated total assets include |
|
|
See the Combined Notes to Consolidated Financial Statements
PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)
(In millions) | Membership Interest | Undistributed Earnings (Losses) | Member’s Equity | |||||||||
Successor | ||||||||||||
Balance, December 31, 2016 | $ | 8,077 | $ | (61 | ) | $ | 8,016 | |||||
Net income | — | 140 | 140 | |||||||||
Distribution to member | — | (69 | ) | (69 | ) | |||||||
Contribution from member | 500 | — | 500 | |||||||||
|
|
|
|
|
| |||||||
Balance, March 31, 2017 | $ | 8,577 | $ | 10 | $ | 8,587 | ||||||
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
(In millions) | Common Stock/ Membership Interest(a) | Retained Earnings/ Undistributed Losses | Accumulated Other Comprehensive Loss, net | Total Shareholders’/ Member’s Equity | ||||||||||||
Predecessor | ||||||||||||||||
Balance at December 31, 2015 | $ | 3,832 | $ | 617 | $ | (36 | ) | $ | 4,413 | |||||||
Net income | — | 19 | — | 19 | ||||||||||||
Original issue shares, net | 3 | — | — | 3 | ||||||||||||
Net activity related to stock-based awards | 3 | — | — | 3 | ||||||||||||
Other comprehensive income, net of income taxes | — | — | 1 | 1 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Balance at March 23, 2016 | $ | 3,838 | $ | 636 | $ | (35 | ) | $ | 4,439 | |||||||
|
|
|
|
|
|
|
| |||||||||
Successor | ||||||||||||||||
Balance at March 24, 2016(b) | $ | 7,200 | $ | — | $ | — | $ | 7,200 | ||||||||
Net loss | — | (91 | ) | — | (91 | ) | ||||||||||
Distribution to member(c) | (301 | ) | — | — | (301 | ) | ||||||||||
Contribution from member | 1,088 | — | — | 1,088 | ||||||||||||
Distribution of net retirement benefit obligation to member | 53 | — | — | 53 | ||||||||||||
Assumption of member liabilities(d) | (62 | ) | — | — | (62 | ) | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Balance at September 30, 2016 | $ | 7,978 | $ | (91 | ) | $ | — | $ | 7,887 | |||||||
|
|
|
|
|
|
|
|
Three Months Ended March 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Operating revenues | ||||||||
Electric operating revenues | $ | 529 | $ | 550 | ||||
Operating revenues from affiliates | 1 | 1 | ||||||
|
|
|
| |||||
Total operating revenues | 530 | 551 | ||||||
|
|
|
| |||||
Operating expenses | ||||||||
Purchased power | 83 | 191 | ||||||
Purchased power from affiliates | 83 | 6 | ||||||
Operating and maintenance | 101 | 288 | ||||||
Operating and maintenance from affiliates | 12 | 2 | ||||||
Depreciation and amortization | 82 | 75 | ||||||
Taxes other than income | 90 | 94 | ||||||
|
|
|
| |||||
Total operating expenses | 451 | 656 | ||||||
|
|
|
| |||||
Operating income (loss) | 79 | (105 | ) | |||||
|
|
|
| |||||
Other income and (deductions) | ||||||||
Interest expense, net | (29 | ) | (37 | ) | ||||
Other, net | 8 | 9 | ||||||
|
|
|
| |||||
Total other income and (deductions) | (21 | ) | (28 | ) | ||||
|
|
|
| |||||
Income (loss) before income taxes | 58 | (133 | ) | |||||
Income taxes | — | (25 | ) | |||||
|
|
|
| |||||
Net income (loss) | $ | 58 | $ | (108 | ) | |||
|
|
|
| |||||
Comprehensive income (loss) | $ | 58 | $ | (108 | ) | |||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
|
|
Three Months Ended March 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Cash flows from operating activities | ||||||||
Net income (loss) | $ | 58 | $ | (108 | ) | |||
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities: | ||||||||
Depreciation and amortization | 82 | 75 | ||||||
Deferred income taxes and amortization of investment tax credits | 5 | (31 | ) | |||||
Othernon-cash operating activities | (15 | ) | 153 | |||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | 45 | (24 | ) | |||||
Receivables from and payables to affiliates, net | (6 | ) | 55 | |||||
Inventories | (10 | ) | 1 | |||||
Accounts payable and accrued expenses | (49 | ) | (4 | ) | ||||
Income taxes | 20 | 151 | ||||||
Pension andnon-pension postretirement benefit contributions | (64 | ) | (1 | ) | ||||
Other assets and liabilities | (37 | ) | (9 | ) | ||||
|
|
|
| |||||
Net cash flows provided by operating activities | 29 | 258 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (139 | ) | (109 | ) | ||||
Purchases of investments | — | (31 | ) | |||||
Changes in restricted cash | — | 2 | ||||||
Other investing activities | (5 | ) | 2 | |||||
|
|
|
| |||||
Net cash flows used in investing activities | (144 | ) | (136 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Changes in short-term borrowings | 144 | (64 | ) | |||||
Issuance of long-term debt | 1 | — | ||||||
Dividends paid on common stock | (30 | ) | (39 | ) | ||||
Other financing activities | (1 | ) | — | |||||
|
|
|
| |||||
Net cash flows provided by (used in) financing activities | 114 | (103 | ) | |||||
|
|
|
| |||||
(Decrease) Increase in cash and cash equivalents | (1 | ) | 19 | |||||
Cash and cash equivalents at beginning of period | 9 | 5 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 8 | $ | 24 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions) | March 31, 2017 | December 31, 2016 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 8 | $ | 9 | ||||
Restricted cash and cash equivalents | 33 | 33 | ||||||
Accounts receivable, net | ||||||||
Customer | 199 | 235 | ||||||
Other | 127 | 150 | ||||||
Inventories, net | 73 | 63 | ||||||
Regulatory assets | 173 | 162 | ||||||
Other | 21 | 32 | ||||||
|
|
|
| |||||
Total current assets | 634 | 684 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 5,659 | 5,571 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 679 | 690 | ||||||
Investments | 101 | 102 | ||||||
Prepaid pension asset | 337 | 282 | ||||||
Other | 7 | 6 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 1,124 | 1,080 | ||||||
|
|
|
| |||||
Total assets | $ | 7,417 | $ | 7,335 | ||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(In millions) | 2016 | 2015 | 2016 | 2015 | ||||||||||||
Operating revenues | ||||||||||||||||
Electric operating revenues | $ | 634 | $ | 591 | $ | 1,692 | $ | 1,637 | ||||||||
Operating revenues from affiliates | 1 | 1 | 3 | 4 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total operating revenues | 635 | 592 | 1,695 | 1,641 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Operating expenses | ||||||||||||||||
Purchased power | 84 | 200 | 340 | 573 | ||||||||||||
Purchased power from affiliates | 129 | — | 223 | — | ||||||||||||
Operating and maintenance | 100 | 110 | 488 | 324 | ||||||||||||
Operating and maintenance from affiliates | 9 | 1 | 20 | 3 | ||||||||||||
Depreciation and amortization | 76 | 66 | 221 | 191 | ||||||||||||
Taxes other than income | 105 | 100 | 287 | 289 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total operating expenses | 503 | 477 | 1,579 | 1,380 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Gain on sale of assets | — | — | 8 | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Operating income | 132 | 115 | 124 | 261 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Other income and (deductions) | ||||||||||||||||
Interest expense, net | (30 | ) | (31 | ) | (98 | ) | (92 | ) | ||||||||
Other, net | 12 | 8 | 28 | 21 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total other income and (deductions) | (18 | ) | (23 | ) | (70 | ) | (71 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Income before income taxes | 114 | 92 | 54 | 190 | ||||||||||||
Income taxes | 35 | 32 | 34 | 62 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Net income attributable to common shareholder | $ | 79 | $ | 60 | $ | 20 | $ | 128 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Comprehensive income | $ | 79 | $ | 60 | $ | 20 | $ | 128 | ||||||||
|
|
|
|
|
|
|
|
See the Combined Notes to Financial Statements
POTOMAC ELECTRIC POWER COMPANY
(Unaudited)
Nine Months Ended September 30, | ||||||||
(In millions) | 2016 | 2015 | ||||||
Cash flows from operating activities | ||||||||
Net income | $ | 20 | $ | 128 | ||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||
Depreciation and amortization | 221 | 191 | ||||||
Deferred income taxes and amortization of investment tax credits | 96 | 70 | ||||||
Other non-cash operating activities | 168 | 42 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (105 | ) | (113 | ) | ||||
Receivables from and payables to affiliates, net | 44 | 2 | ||||||
Inventories | 3 | (5 | ) | |||||
Accounts payable and accrued expenses | 7 | (1 | ) | |||||
Income taxes | 139 | — | ||||||
Pension and non-pension postretirement benefit contributions | (6 | ) | (7 | ) | ||||
Other assets and liabilities | (83 | ) | (94 | ) | ||||
|
|
|
| |||||
Net cash flows provided by operating activities | 504 | 213 | ||||||
|
|
|
| |||||
Cash flows from investing activities | ||||||||
Capital expenditures | (392 | ) | (374 | ) | ||||
Proceeds from sale of long-lived asset | 12 | — | ||||||
Purchases of investments | (32 | ) | — | |||||
Changes in restricted cash | (31 | ) | 3 | |||||
Other investing activities | 8 | 14 | ||||||
|
|
|
| |||||
Net cash flows used in investing activities | (435 | ) | (357 | ) | ||||
|
|
|
| |||||
Cash flows from financing activities | ||||||||
Changes in short-term borrowings | (64 | ) | (56 | ) | ||||
Issuance of long-term debt | 2 | 208 | ||||||
Retirement of long-term debt | (5 | ) | (17 | ) | ||||
Dividends paid on common stock | (92 | ) | (91 | ) | ||||
Contribution from parent | 187 | 112 | ||||||
Other financing activities | — | (8 | ) | |||||
|
|
|
| |||||
Net cash flows provided by financing activities | 28 | 148 | ||||||
|
|
|
| |||||
Increase in cash and cash equivalents | 97 | 4 | ||||||
Cash and cash equivalents at beginning of period | 5 | 6 | ||||||
|
|
|
| |||||
Cash and cash equivalents at end of period | $ | 102 | $ | 10 | ||||
|
|
|
|
See the Combined Notes to Financial Statements
POTOMAC ELECTRIC POWER COMPANY
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | ||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 102 | $ | 5 | ||||
Restricted cash and cash equivalents | 33 | 2 | ||||||
Accounts receivable, net | ||||||||
Customer | 292 | 230 | ||||||
Other | 148 | 261 | ||||||
Inventories, net | 63 | 67 | ||||||
Regulatory assets | 122 | 140 | ||||||
Other | 4 | 21 | ||||||
|
|
|
| |||||
Total current assets | 764 | 726 | ||||||
|
|
|
| |||||
Property, plant and equipment, net | 5,409 | 5,162 | ||||||
Deferred debits and other assets | ||||||||
Regulatory assets | 676 | 661 | ||||||
Investments | 100 | 68 | ||||||
Prepaid pension asset | 266 | 287 | ||||||
Other | 4 | 4 | ||||||
|
|
|
| |||||
Total deferred debits and other assets | 1,046 | 1,020 | ||||||
|
|
|
| |||||
Total assets | $ | 7,219 | $ | 6,908 | ||||
|
|
|
|
See the Combined Notes to Financial Statements
POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | ||||||||||||
LIABILITIES AND SHAREHOLDER’S EQUITY | ||||||||||||||||
Current liabilities | ||||||||||||||||
Short-term borrowings | $ | — | $ | 64 | $ | 167 | $ | 23 | ||||||||
Long-term debt due within one year | 12 | 11 | 17 | 16 | ||||||||||||
Accounts payable | 139 | 145 | 141 | 209 | ||||||||||||
Accrued expenses | 145 | 119 | 125 | 113 | ||||||||||||
Payables to affiliates | 74 | 30 | 68 | 74 | ||||||||||||
Customer deposits | 53 | 46 | 53 | 53 | ||||||||||||
Regulatory liabilities | 20 | 15 | 10 | 11 | ||||||||||||
Merger related obligation | 63 | — | 47 | 68 | ||||||||||||
Other | 14 | 25 | 23 | 29 | ||||||||||||
|
|
|
| |||||||||||||
Total current liabilities | 520 | 455 | 651 | 596 | ||||||||||||
|
|
|
| |||||||||||||
Long-term debt | 2,338 | 2,340 | 2,333 | 2,333 | ||||||||||||
Deferred credits and other liabilities | ||||||||||||||||
Regulatory liabilities | 24 | 29 | 19 | 20 | ||||||||||||
Deferred income taxes and unamortized investment tax credits | 1,845 | 1,723 | 1,913 | 1,910 | ||||||||||||
Non-pension postretirement benefit obligations | 46 | 49 | 41 | 43 | ||||||||||||
Other | 124 | 72 | 132 | 133 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred credits and other liabilities | 2,039 | 1,873 | 2,105 | 2,106 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities | 4,897 | 4,668 | 5,089 | 5,035 | ||||||||||||
|
|
|
| |||||||||||||
Commitments and contingencies | ||||||||||||||||
Shareholder’s equity | ||||||||||||||||
Common stock | 1,309 | 1,122 | 1,309 | 1,309 | ||||||||||||
Retained earnings | 1,013 | 1,118 | 1,019 | 991 | ||||||||||||
|
|
|
| |||||||||||||
Total shareholder’s equity | 2,322 | 2,240 | 2,328 | 2,300 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities and shareholder’s equity | $ | 7,219 | $ | 6,908 | $ | 7,417 | $ | 7,335 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
POTOMAC ELECTRIC POWER COMPANY
STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
(In millions) | Common Stock | Retained Earnings | Total Shareholder’s Equity | |||||||||
Balance, December 31, 2015 | $ | 1,122 | $ | 1,118 | $ | 2,240 | ||||||
Net Income | — | 20 | 20 | |||||||||
Common stock dividends | — | (125 | ) | (125 | ) | |||||||
Contribution from parent | 187 | — | 187 | |||||||||
|
|
|
|
|
| |||||||
Balance, September 30, 2016 | $ | 1,309 | $ | 1,013 | $ | 2,322 | ||||||
|
|
|
|
|
|
(In millions) | Common Stock | Retained Earnings | Total Shareholder’s Equity | |||||||||
Balance, December 31, 2016 | $ | 1,309 | $ | 991 | $ | 2,300 | ||||||
Net income | — | 58 | 58 | |||||||||
Common stock dividends | — | (30 | ) | (30 | ) | |||||||
|
|
|
|
|
| |||||||
Balance, March 31, 2017 | $ | 1,309 | $ | 1,019 | $ | 2,328 | ||||||
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
(In millions) | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||
Operating revenues | ||||||||||||||||||||||||
Electric operating revenues | $ | 312 | $ | 294 | $ | 866 | $ | 871 | $ | 294 | $ | 301 | ||||||||||||
Natural gas operating revenues | 17 | 19 | 102 | 129 | 66 | 59 | ||||||||||||||||||
Operating revenues from affiliates | 2 | 1 | 6 | 4 | 2 | 2 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total operating revenues | 331 | 314 | 974 | 1,004 | 362 | 362 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||
Purchased power | 81 | 143 | 297 | 435 | 77 | 147 | ||||||||||||||||||
Purchased fuel | 6 | 8 | 41 | 65 | 29 | 25 | ||||||||||||||||||
Purchased power from affiliate | 63 | — | 110 | — | 51 | 4 | ||||||||||||||||||
Operating and maintenance | 50 | 77 | 327 | 233 | 66 | 204 | ||||||||||||||||||
Operating and maintenance from affiliates | 5 | — | 11 | 1 | 7 | — | ||||||||||||||||||
Depreciation, amortization and accretion | 44 | 40 | 120 | 113 | ||||||||||||||||||||
Depreciation and amortization | 39 | 39 | ||||||||||||||||||||||
Taxes other than income | 14 | 14 | 42 | 39 | 15 | 15 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total operating expenses | 263 | 282 | 948 | 886 | 284 | 434 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Gain on sale of asset | 4 | — | 4 | — | ||||||||||||||||||||
|
|
|
| |||||||||||||||||||||
Operating income | 72 | 32 | 30 | 118 | ||||||||||||||||||||
Operating income (loss) | 78 | (72 | ) | |||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Other income and (deductions) | ||||||||||||||||||||||||
Interest expense, net | (12 | ) | (12 | ) | (37 | ) | (37 | ) | (13 | ) | (12 | ) | ||||||||||||
Other, net | 3 | 4 | 9 | 8 | 3 | 3 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total other income and (deductions) | (9 | ) | (8 | ) | (28 | ) | (29 | ) | (10 | ) | (9 | ) | ||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Income before income taxes | 63 | 24 | 2 | 89 | ||||||||||||||||||||
Income (loss) before income taxes | 68 | (81 | ) | |||||||||||||||||||||
Income taxes | 19 | 9 | 18 | 34 | 11 | (9 | ) | |||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Net income (loss) attributable to common shareholder | $ | 44 | $ | 15 | $ | (16 | ) | $ | 55 | |||||||||||||||
Net income (loss) | $ | 57 | $ | (72 | ) | |||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Comprehensive income (loss) | $ | 44 | $ | 15 | $ | (16 | ) | $ | 55 | $ | 57 | $ | (72 | ) | ||||||||||
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
DELMARVA POWER & LIGHT COMPANY
(Unaudited)
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||
(In millions) | 2016 | 2015 | 2017 | 2016 | ||||||||||||
Cash flows from operating activities | ||||||||||||||||
Net (loss) income | $ | (16 | ) | $ | 55 | |||||||||||
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities: | ||||||||||||||||
Depreciation, amortization and accretion | 120 | 113 | ||||||||||||||
Net income (loss) | $ | 57 | $ | (72 | ) | |||||||||||
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities: | ||||||||||||||||
Depreciation and amortization | 39 | 39 | ||||||||||||||
Deferred income taxes and amortization of investment tax credits | 69 | 40 | 13 | (4 | ) | |||||||||||
Other non-cash operating activities | 99 | 31 | (7 | ) | 118 | |||||||||||
Changes in assets and liabilities: | ||||||||||||||||
Accounts receivable | 8 | (33 | ) | 6 | 4 | |||||||||||
Receivables from and payables to affiliates, net | 12 | 5 | 1 | 20 | ||||||||||||
Inventories | — | 4 | 1 | 1 | ||||||||||||
Accounts payable and accrued expenses | (8 | ) | (5 | ) | 14 | (3 | ) | |||||||||
Collateral received | 1 | — | ||||||||||||||
Income taxes | 52 | — | 21 | 52 | ||||||||||||
Other assets and liabilities | (70 | ) | (22 | ) | (23 | ) | (8 | ) | ||||||||
|
|
|
| |||||||||||||
Net cash flows provided by operating activities | 267 | 188 | 122 | 147 | ||||||||||||
|
|
|
| |||||||||||||
Cash flows from investing activities | ||||||||||||||||
Capital expenditures | (260 | ) | (246 | ) | (82 | ) | (81 | ) | ||||||||
Proceeds from sale of long-lived asset | 4 | — | ||||||||||||||
Changes in restricted cash | — | 5 | ||||||||||||||
Other investing activities | 2 | 1 | 2 | — | ||||||||||||
|
|
|
| |||||||||||||
Net cash flows used in investing activities | (254 | ) | (240 | ) | (80 | ) | (81 | ) | ||||||||
|
|
|
| |||||||||||||
Cash flows from financing activities | ||||||||||||||||
Changes in short-term borrowings | (88 | ) | (40 | ) | — | (30 | ) | |||||||||
Issuance of long-term debt | — | 200 | ||||||||||||||
Retirement of long-term debt | — | (100 | ) | (14 | ) | — | ||||||||||
Dividends paid on common stock | (39 | ) | (80 | ) | (30 | ) | (38 | ) | ||||||||
Contribution from parent | 113 | 75 | ||||||||||||||
Other financing activities | — | (2 | ) | |||||||||||||
|
|
|
| |||||||||||||
Net cash flows (used in) provided by financing activities | (14 | ) | 53 | |||||||||||||
Net cash flows used in financing activities | (44 | ) | (68 | ) | ||||||||||||
|
|
|
| |||||||||||||
(Decrease) Increase in cash and cash equivalents | (1 | ) | 1 | |||||||||||||
Decrease in cash and cash equivalents | (2 | ) | (2 | ) | ||||||||||||
Cash and cash equivalents at beginning of period | 5 | 4 | 46 | 5 | ||||||||||||
|
|
|
| |||||||||||||
Cash and cash equivalents at end of period | $ | 4 | $ | 5 | $ | 44 | $ | 3 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
DELMARVA POWER & LIGHT COMPANY
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | ||||||||||||
ASSETS | ||||||||||||||||
Current assets | ||||||||||||||||
Cash and cash equivalents | $ | 4 | $ | 5 | $ | 44 | $ | 46 | ||||||||
Accounts receivable, net | ||||||||||||||||
Customer | 134 | 154 | 131 | 136 | ||||||||||||
Other | 44 | 96 | 39 | 63 | ||||||||||||
Receivables from affiliates | — | 3 | ||||||||||||||
Inventories, net | ||||||||||||||||
Gas held in storage | 8 | 8 | 3 | 7 | ||||||||||||
Materials and supplies | 32 | 32 | 35 | 32 | ||||||||||||
Regulatory assets | 62 | 72 | 66 | 59 | ||||||||||||
Other | 17 | 21 | 21 | 24 | ||||||||||||
|
|
|
| |||||||||||||
Total current assets | 301 | 388 | 339 | 370 | ||||||||||||
|
|
|
| |||||||||||||
Property, plant and equipment, net | 3,222 | 3,070 | 3,334 | 3,273 | ||||||||||||
Deferred debits and other assets | ||||||||||||||||
Regulatory assets | 297 | 299 | 301 | 289 | ||||||||||||
Investments | 1 | — | ||||||||||||||
Goodwill | 8 | 8 | 8 | 8 | ||||||||||||
Prepaid pension asset | 188 | 202 | 203 | 206 | ||||||||||||
Other | 7 | 2 | 5 | 7 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred debits and other assets | 500 | 511 | 518 | 510 | ||||||||||||
|
|
|
| |||||||||||||
Total assets | $ | 4,023 | $ | 3,969 | $ | 4,191 | $ | 4,153 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | ||||||||||||
LIABILITIES AND SHAREHOLDER’S EQUITY | ||||||||||||||||
Current liabilities | ||||||||||||||||
Short-term borrowings | $ | 17 | $ | 105 | ||||||||||||
Long-term debt due within one year | 218 | 204 | $ | 109 | $ | 119 | ||||||||||
Accounts payable | 74 | 109 | 106 | 88 | ||||||||||||
Accrued expenses | 47 | 31 | 44 | 36 | ||||||||||||
Payables to affiliates | 34 | 20 | 36 | 38 | ||||||||||||
Customer deposits | 37 | 31 | 36 | 36 | ||||||||||||
Regulatory liabilities | 46 | 49 | 47 | 43 | ||||||||||||
Merger related obligation | 12 | — | 4 | 13 | ||||||||||||
Other | 10 | 15 | 6 | 8 | ||||||||||||
|
|
|
| |||||||||||||
Total current liabilities | 495 | 564 | 388 | 381 | ||||||||||||
|
|
|
| |||||||||||||
Long-term debt | 1,047 | 1,061 | 1,217 | 1,221 | ||||||||||||
Deferred credits and other liabilities | ||||||||||||||||
Regulatory liabilities | 100 | 111 | 95 | 97 | ||||||||||||
Deferred income taxes and unamortized investment tax credits | 1,016 | 945 | 1,072 | 1,056 | ||||||||||||
Non-pension postretirement benefit obligations | 19 | 19 | 17 | 19 | ||||||||||||
Other | 51 | 32 | 49 | 53 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred credits and other liabilities | 1,186 | 1,107 | 1,233 | 1,225 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities | 2,728 | 2,732 | 2,838 | 2,827 | ||||||||||||
|
|
|
| |||||||||||||
Commitments and contingencies | ||||||||||||||||
Shareholder’s equity | ||||||||||||||||
Common stock | 725 | 612 | 764 | 764 | ||||||||||||
Retained earnings | 570 | 625 | 589 | 562 | ||||||||||||
|
|
|
| |||||||||||||
Total shareholder’s equity | 1,295 | 1,237 | 1,353 | 1,326 | ||||||||||||
|
|
|
| |||||||||||||
Total liabilities and shareholder’s equity | $ | 4,023 | $ | 3,969 | $ | 4,191 | $ | 4,153 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
DELMARVA POWER & LIGHT COMPANY
STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
(In millions) | Common Stock | Retained Earnings | Total Shareholder’s Equity | |||||||||
Balance, December 31, 2015 | $ | 612 | $ | 625 | $ | 1,237 | ||||||
Net loss | — | (16 | ) | (16 | ) | |||||||
Common stock dividends | — | (39 | ) | (39 | ) | |||||||
Contribution from parent | 113 | — | 113 | |||||||||
|
|
|
|
|
| |||||||
Balance, September 30, 2016 | $ | 725 | $ | 570 | $ | 1,295 | ||||||
|
|
|
|
|
|
(In millions) | Common Stock | Retained Earnings | Total Shareholder’s Equity | |||||||||
Balance, December 31, 2016 | $ | 764 | $ | 562 | $ | 1,326 | ||||||
Net income | — | 57 | 57 | |||||||||
Common stock dividends | — | (30 | ) | (30 | ) | |||||||
|
|
|
|
|
| |||||||
Balance, March 31, 2017 | $ | 764 | $ | 589 | $ | 1,353 | ||||||
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
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, | Three Months Ended March 31, | ||||||||||||||||||||||
(In millions) | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||
Operating revenues | ||||||||||||||||||||||||
Electric operating revenues | $ | 420 | $ | 385 | $ | 979 | $ | 1,001 | $ | 274 | $ | 290 | ||||||||||||
Operating revenues from affiliates | 1 | 1 | 3 | 2 | 1 | 1 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total operating revenues | 421 | 386 | 982 | 1,003 | 275 | 291 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||
Purchased power | 206 | 214 | 491 | 552 | 128 | 157 | ||||||||||||||||||
Purchased power from affiliates | 15 | — | 29 | — | 9 | 1 | ||||||||||||||||||
Operating and maintenance | 62 | 69 | 336 | 205 | 69 | 211 | ||||||||||||||||||
Operating and maintenance from affiliates | 5 | 1 | 10 | 2 | 7 | 1 | ||||||||||||||||||
Depreciation, amortization and accretion | 49 | 49 | 130 | 135 | ||||||||||||||||||||
Depreciation and amortization | 35 | 40 | ||||||||||||||||||||||
Taxes other than income | 1 | 2 | 6 | 5 | 2 | 2 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total operating expenses | 338 | 335 | 1,002 | 899 | 250 | 412 | ||||||||||||||||||
|
|
|
| |||||||||||||||||||||
Gain on sale of assets | — | — | 1 | — | ||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Operating income (loss) | 83 | 51 | (19 | ) | 104 | 25 | (121 | ) | ||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Other income and (deductions) | ||||||||||||||||||||||||
Interest expense, net | (15 | ) | (16 | ) | (47 | ) | (48 | ) | (15 | ) | (16 | ) | ||||||||||||
Other, net | 2 | 1 | 8 | 4 | 2 | 4 | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total other income and (deductions) | (13 | ) | (15 | ) | (39 | ) | (44 | ) | (13 | ) | (12 | ) | ||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Income (loss) before income taxes | 70 | 36 | (58 | ) | 60 | 12 | (133 | ) | ||||||||||||||||
Income taxes | 23 | 14 | (8 | ) | 23 | (16 | ) | (33 | ) | |||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Net income (loss) attributable to common shareholder | $ | 47 | $ | 22 | $ | (50 | ) | $ | 37 | |||||||||||||||
Net income (loss) | $ | 28 | $ | (100 | ) | |||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Comprehensive income (loss) | $ | 47 | $ | 22 | $ | (50 | ) | $ | 37 | $ | 28 | $ | (100 | ) | ||||||||||
|
|
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||
(In millions) | 2016 | 2015 | 2017 | 2016 | ||||||||||||
Cash flows from operating activities | ||||||||||||||||
Net (loss) income | $ | (50 | ) | $ | 37 | |||||||||||
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities: | ||||||||||||||||
Depreciation, amortization and accretion | 130 | 135 | ||||||||||||||
Net income (loss) | $ | 28 | $ | (100 | ) | |||||||||||
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities: | ||||||||||||||||
Depreciation and amortization | 35 | 40 | ||||||||||||||
Deferred income taxes and amortization of investment tax credits | 14 | 13 | (7 | ) | (33 | ) | ||||||||||
Other non-cash operating activities | 138 | 27 | 2 | 132 | ||||||||||||
Changes in assets and liabilities: | ||||||||||||||||
Accounts receivable | (32 | ) | (87 | ) | 14 | 5 | ||||||||||
Receivables from and payables to affiliates, net | 9 | 1 | (5 | ) | 20 | |||||||||||
Inventories | (1 | ) | (1 | ) | (1 | ) | (2 | ) | ||||||||
Accounts payable and accrued expenses | 10 | 35 | (5 | ) | 19 | |||||||||||
Income taxes | 184 | 10 | 3 | 168 | ||||||||||||
Other assets and liabilities | (87 | ) | 8 | (6 | ) | (3 | ) | |||||||||
|
|
|
| |||||||||||||
Net cash flows provided by operating activities | 315 | 178 | 58 | 246 | ||||||||||||
|
|
|
| |||||||||||||
Cash flows from investing activities | ||||||||||||||||
Capital expenditures | (227 | ) | (212 | ) | (88 | ) | (101 | ) | ||||||||
Proceeds from sale of long-lived asset | 2 | — | ||||||||||||||
Changes in restricted cash | (4 | ) | (6 | ) | 2 | 1 | ||||||||||
Other investing activities | 2 | 2 | 1 | — | ||||||||||||
|
|
|
| |||||||||||||
Net cash flows used in investing activities | (227 | ) | (216 | ) | (85 | ) | (100 | ) | ||||||||
|
|
|
| |||||||||||||
Cash flows from financing activities | ||||||||||||||||
Changes in short-term borrowings | (5 | ) | 98 | — | (5 | ) | ||||||||||
Retirement of long-term debt | (35 | ) | (46 | ) | (10 | ) | (11 | ) | ||||||||
Dividends paid on common stock | (24 | ) | (12 | ) | (10 | ) | (11 | ) | ||||||||
Contribution from parent | 139 | — | ||||||||||||||
Other financing activities | (1 | ) | — | |||||||||||||
|
|
|
| |||||||||||||
Net cash flows provided by financing activities | 74 | 40 | ||||||||||||||
Net cash flows used in financing activities | (20 | ) | (27 | ) | ||||||||||||
|
|
|
| |||||||||||||
Increase in cash and cash equivalents | 162 | 2 | ||||||||||||||
(Decrease) Increase in cash and cash equivalents | (47 | ) | 119 | |||||||||||||
Cash and cash equivalents at beginning of period | 3 | 2 | 101 | 3 | ||||||||||||
|
|
|
| |||||||||||||
Cash and cash equivalents at end of period | $ | 165 | $ | 4 | $ | 54 | $ | 122 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | ||||||||||||
ASSETS | ||||||||||||||||
Current assets | ||||||||||||||||
Cash and cash equivalents | $ | 165 | $ | 3 | $ | 54 | $ | 101 | ||||||||
Restricted cash and cash equivalents | 15 | 12 | 7 | 9 | ||||||||||||
Accounts receivable, net | ||||||||||||||||
Customer | 168 | 156 | 111 | 125 | ||||||||||||
Other | 46 | 242 | 41 | 44 | ||||||||||||
Receivables from affiliates | 2 | — | ||||||||||||||
Inventories, net | 22 | 23 | 23 | 22 | ||||||||||||
Prepaid utility taxes | 10 | — | ||||||||||||||
Regulatory assets | 89 | 98 | 94 | 96 | ||||||||||||
Other | 3 | 12 | 3 | 2 | ||||||||||||
|
|
|
| |||||||||||||
Total current assets | 520 | 546 | 333 | 399 | ||||||||||||
|
|
|
| |||||||||||||
Property, plant and equipment, net | 2,456 | 2,322 | 2,583 | 2,521 | ||||||||||||
Deferred debits and other assets | ||||||||||||||||
Regulatory assets | 412 | 414 | 407 | 405 | ||||||||||||
Long-term note receivable | 4 | 4 | 4 | 4 | ||||||||||||
Prepaid pension asset | 73 | 82 | 82 | 84 | ||||||||||||
Other | 42 | 19 | 42 | 44 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred debits and other assets | 531 | 519 | 535 | 537 | ||||||||||||
|
|
|
| |||||||||||||
Total assets(a) | $ | 3,507 | $ | 3,387 | $ | 3,451 | $ | 3,457 | ||||||||
|
|
|
|
See the Combined Notes to Consolidated Financial Statements
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions) | September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | ||||||||||||
LIABILITIES AND SHAREHOLDER’S EQUITY | ||||||||||||||||
Current liabilities | ||||||||||||||||
Short-term borrowings | $ | — | $ | 5 | ||||||||||||
Long-term debt due within one year | 38 | 48 | $ | 33 | $ | 35 | ||||||||||
Accounts payable | 110 | 96 | 125 | 132 | ||||||||||||
Accrued expenses | 72 | 70 | 50 | 38 | ||||||||||||
Payables to affiliates | 27 | 16 | 24 | 29 | ||||||||||||
Customer deposits | 35 | 30 | 32 | 33 | ||||||||||||
Regulatory liabilities | 35 | 18 | 25 | 25 | ||||||||||||
Merger related obligation | 14 | — | 22 | 20 | ||||||||||||
Other | 7 | 14 | 9 | 8 | ||||||||||||
|
|
|
| |||||||||||||
Total current liabilities | 338 | 297 | 320 | 320 | ||||||||||||
|
|
|
| |||||||||||||
Long-term debt | 1,129 | 1,153 | 1,112 | 1,120 | ||||||||||||
Deferred credits and other liabilities | ||||||||||||||||
Deferred income taxes and unamortized investment tax credits | 908 | 885 | 911 | 917 | ||||||||||||
Non-pension postretirement benefit obligations | 35 | 33 | 33 | 34 | ||||||||||||
Regulatory liabilities | 1 | 7 | ||||||||||||||
Other | 31 | 12 | 23 | 32 | ||||||||||||
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Total deferred credits and other liabilities | 975 | 937 | 967 | 983 | ||||||||||||
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Total liabilities(a) | 2,442 | 2,387 | 2,399 | 2,423 | ||||||||||||
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Commitments and contingencies | ||||||||||||||||
Shareholder’s equity | ||||||||||||||||
Common stock | 912 | 773 | 912 | 912 | ||||||||||||
Retained earnings | 153 | 227 | 140 | 122 | ||||||||||||
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Total shareholder’s equity | 1,065 | 1,000 | 1,052 | 1,034 | ||||||||||||
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Total liabilities and shareholder’s equity | $ | 3,507 | $ | 3,387 | $ | 3,451 | $ | 3,457 | ||||||||
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(a) | ACE’s consolidated total assets include |
See the Combined Notes to Consolidated Financial Statements
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
(In millions) | Common Stock | Retained Earnings | Total Shareholder’s Equity | |||||||||
Balance, December 31, 2015 | $ | 773 | $ | 227 | $ | 1,000 | ||||||
Net loss | — | (50 | ) | (50 | ) | |||||||
Common stock dividends | — | (24 | ) | (24 | ) | |||||||
Contribution from parent | 139 | — | 139 | |||||||||
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Balance, September 30, 2016 | $ | 912 | $ | 153 | $ | 1,065 | ||||||
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(In millions) | Common Stock | Retained Earnings | Total Shareholder’s Equity | |||||||||
Balance, December 31, 2016 | $ | 912 | $ | 122 | $ | 1,034 | ||||||
Net income | — | 28 | 28 | |||||||||
Common stock dividends | — | (10 | ) | (10 | ) | |||||||
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Balance, March 31, 2017 | $ | 912 | $ | 140 | $ | 1,052 | ||||||
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See the Combined Notes to Consolidated Financial Statements
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
Index to Combined Notes To Consolidated Financial Statements
The notes to the consolidated financial statements that follow are a combined presentation. The following list indicates the Registrants to which the footnotes apply:
Applicable Notes
Registrant | 1 | 2 | 3 | 4 | 5 | 6 | 7 | 8 | 9 | 10 | 11 | 12 | 13 | 14 | 15 | 16 | 17 | 18 | 19 | 20 | 1 | 2 | 3 | 4 | 5 | 6 | 7 | 8 | 9 | 10 | 11 | 12 | 13 | 14 | 15 | 16 | 17 | 18 | 19 | 20 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon Corporation | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon Generation Company, LLC | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Company | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Company | . | . | . | . | . | . | . | . | . | . | . | . | . | . | �� | . | . | . | . | . | . | . | . | . | . | . | . | . | . | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pepco Holdings LLC | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Potomac Electric Power Company | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Delmarva Power & Light Company | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Atlantic City Electric Company | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . | . |
1. Significant Accounting Policies (All Registrants)
Description of Business (All Registrants)
Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution and transmission businesses. Prior to March 23, 2016, Exelon’s principal, wholly owned subsidiaries included Generation, ComEd, PECO and BGE. On March 23, 2016, in conjunction with the Amended and Restated Agreement and Plan of Merger (the PHI Merger Agreement), Purple Acquisition Corp, a wholly owned subsidiary of Exelon, merged with and into PHI, with PHI continuing as the surviving entity as a wholly owned subsidiary of Exelon. PHI is a utility services holding company engaged through its principal wholly owned subsidiaries, Pepco, DPL and ACE, in the energy distribution and transmission businesses. Refer to Note 4 — Mergers, Acquisitions and Dispositions for further information regarding the merger transaction.
The energy generation business includes:
• | Generation: Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services. Generation has six reportable segments consisting of theMid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. |
The energy delivery businesses include:
• | ComEd: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in northern Illinois, including the City of Chicago. |
• | PECO: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in the Pennsylvania counties surrounding the City of Philadelphia. |
• | BGE: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in central Maryland, including the City of Baltimore. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
|
• | Pepco: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. |
• | DPL: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware. |
• | ACE: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in southern New Jersey. |
Basis of Presentation (All Registrants)
Pursuant toAs a result of the acquisition of PHI, Exelon’s financial reporting reflects PHI’s consolidated financial results subsequent to the March 23, 2016, acquisition date. Exelon has accounted for the merger transaction applying the acquisition method of accounting, which requires the assets acquired and liabilities assumed by Exelon to be reported in Exelon’s financial statements at fair value, with any excess of the purchase price over the fair value of net assets acquired reported as goodwill. Exelon has pushed-down the application of the acquisition method of accounting to the consolidated financial statements of PHI such that the assets and liabilities of PHI are similarly recorded at their respective fair values, and goodwill has been established as of the acquisition date. Accordingly, the consolidated financial statements of PHI for periods before and after the March 23, 2016, acquisition date reflect different bases of accounting, and the financial positions and the results of operations of the predecessor and successor periods are not comparable. The acquisition method of accounting has not been pushed down to PHI’s wholly-owned subsidiary utility registrants, Pepco, DPL and ACE.
For financial statement purposes, beginning on March 24, 2016, disclosures that had solely related to PHI, Pepco, DPL or ACE activities now also apply to Exelon, unless otherwise noted. When appropriate, Exelon, Generation, ComEd, PECO, BGE,
In the second quarter of 2016, an error was identified and corrected related to the PHI Pepco, DPL and ACE are named specifically for their related activities and disclosures.
Certain prior year amounts in thesuccessor period Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated StatementsStatement of Cash Flows of PHI, Pepco, DPL and ACE have been reclassifiedfor the period March 24, 2016 to conformMarch 31, 2016. The $46 million classification error related to the presentation of these amountschanges in Receivables from and payables to the current period presentationaffiliates, net within Cash flows from operating activities and Change in Exelon’s financial statements. Most significantlyExelon intercompany money pool within Cash flows from financing activities. As revised for PHI, Pepco, DPL and ACE, current regulatory assets and liabilities have been presented separately from the non-current portions in each respective Consolidated Balance Sheet where recovery or refund is expected within the next 12 months. Additionally, for PHI, Pepco, DPL and ACE, the removal cost within Accumulated depreciation was reclassified to the Regulatory liability or Regulatory asset account to align with Exelon’s presentation. The reclassifications were not considered errors for PHI, Pepco, DPL or ACE.
In its December 31, 2015 Form 10-K, Exelon revised the presentation on the Consolidated Statements of Operations and Comprehensive Income for PECO and BGE to reflect separately operating revenues from the sale of electricity and operating revenues from the sale of natural gas, as well as to reflect separately purchased power expense and purchased fuel expense within the operating expenses section of the Consolidated Statement of Operations and Comprehensive Income. Further, Exelon revised the presentation from Total operating revenues to “Rate-regulated utility revenues” and “Competitive businesses revenues” on the face of Exelon’s Consolidated Statement of Operations and Comprehensive Income for all periods presented. Similarly, Exelon has separately
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
presented Rate-regulated utility purchased power and fuel expense and Competitive businesses purchased power and fuel expense on the face of Exelon’s Consolidated Statement of Operations and Comprehensive Income for all periods presented. The reclassifications described herein were made for presentation purposes and did not affect any of the Registrants’ total operating revenues or net income.
ACE Basic Generation Service Recovery Mechanism
ACE has a recovery mechanism for purchased power costs associated with BGS. ACE records a deferred energy supply costs regulatory asset or regulatory liability for under or over-recovered costs that are expected to be recovered from or refunded to ACE customers, respectively. In the first quarter of 2016, ACE changed its method2017, the successor period statement of accounting for determining under or over-recovered costs in this recovery mechanism to include unbilled revenues in the determination of under or over-recovered costs. ACE believes this change is preferable as it better reflects the economic impacts of dollar-for-dollar cost recovery mechanisms. ACE applied the change retrospectively. The impact of the change was a $12 million reduction to ACE’s opening Retained earnings as of January 1, 2014 with a corresponding reduction to Regulatory assets. The impact of the change on Net income attributable to common shareholder was an increase of $8 million and $9 millioncash flows for the threeperiod March 24, 2016 to March 31, 2016 presents Cash flows used in operating activities of $3 million, a decrease of $46 million from the originally reported amount, and nine months ended September 30, 2015, respectively.
ClassificationCash flows used in financing activities of Interest on Uncertain Tax Positions
In$135 million, a decrease of $46 million from the first quarter of 2016, PHI, Pepco, DPL and ACE changed their accounting principle for classification of interest on uncertain tax positions. PHI, Pepco, DPL and ACE have reclassified interest on uncertain tax positions as interest expense from income tax expense inoriginally reported amount. Management has concluded that the Consolidated Statements of Operations and Comprehensive Income. GAAP doeserror is not addressmaterial to the preferability of one acceptable method of accounting over the other for the classification of interest on uncertain tax positions. However, PHI, Pepco, DPL, and ACE believe this change is preferable for comparability of theirpreviously issued financial statements with the financial statements of the other Registrants in the combined filing, for consistency with FERC classification, and for a more appropriate representation of the effective tax rate as they manage the settlement of uncertain tax positions and interest expense separately. PHI, Pepco, DPL, and ACE applied the change retrospectively. The reclassification in the Consolidated Statements of Operations and Comprehensive Income for the nine months ended September 30, 2015 is $1 million for PHI and less than $1 million for Pepco, DPL and ACE. The reclassification amount is more significant for the year ended December 31, 2015.statements.
Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
The accompanying consolidated financial statements as of September 30,March 31, 2017 and 2016 and 2015 and for the three and nine months then ended 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, 20152016 Consolidated Balance Sheets were obtainedderived 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 the fiscal year ending December 31, 2016.2017. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form10-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.
2. New Accounting Pronouncements (All Registrants)
Exelon has identified the following new accounting standards that have been recently adopted.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share2. New Accounting Standards (All Registrants)
In May 2015, the FASB issued authoritative guidance that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the Balance Sheet. The guidance also simplified the disclosure requirements for investments valued using the practical expedient. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015. The Registrants adopted the standard in the first quarter of 2016, and applied the guidance retrospectively to all prior periods presented. The adoption of this guidance had no impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income and Consolidated Statements of Cash Flows. See Note 8 — Fair Value of Financial Assets and Liabilities for the disclosure impacts.
Customer’sNew Accounting for Fees Paid in a Cloud Computing ArrangementStandards Issued and Not Yet Adopted:
In April 2015, The following new authoritative accounting guidance issued by the FASB issued authoritativehas not yet been adopted and reflected by the Registrants in their consolidated financial statements. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance that clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. A cloud computing arrangement would include a software license if (1) the customer has a contractual right to take possession of the software at any time during the hosting period without significant penalty and (2) it is feasible for the customer to either operate the softwaremay have (which could be material) on its own hardware or contract with another party unrelated to the vendor to host the software. If the arrangement does not contain a software license, it would be accounted for as a service contract. The Registrants prospectively adopted the standard in the first quarter of 2016. The adoption of this guidance had no impact on the Registrants’their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures.
Amendments to the Consolidation Analysis
In February 2015, the FASB issued authoritative guidance that amends the consolidation analysis for variable interest entities (VIEs)disclosures, as well as voting interest entities. The new guidance primarily (1) changes the VIE assessment of limited partnerships, (2) amends the effect that fees paidpotential to a decision maker or service provider have on the VIE analysis, (3) amends how variable interests held by a reporting entity’s related parties and de facto agents impact its consolidation conclusion, (4) clarifies how to determine whether equity holders (as a group) have power over an entity, and (5) provides a scope exception for registered and similar unregistered money market funds. The guidance became effective for the Registrants January 1, 2016. The Registrants adopted the standard in the first quarter of 2016.early adopt where applicable. The Registrants have evaluated the standard and have not identified any changes to consolidation conclusions as a resultassessed other FASB issuances of the new guidance, but have identified additional entities that are now considered VIEs. See Note 3 — Variable Interest Entities for the disclosure impacts.
The following issued accounting standards which are not yet required to be reflected inlisted below given the consolidatedcurrent expectation such standards will not significantly impact the Registrants’ financial statements of the Registrants.reporting.
Revenue from Contracts with Customers
In (Issued May 2014 the FASB issued authoritative guidance that changesand subsequently amended to address implementation questions): Changes the criteria for recognizing revenue from a contract with a customer. The new revenue recognition guidance, including subsequent amendments, is effective for annual reporting periods beginning on or after December 15, 2017, with the option to early adopt the standard for annual periods beginning on or after December 15, 2016. The Registrants do not plan to early adopt the standard.
The new standard replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. In addition, the Registrants will be required to capitalize costs to acquire new contracts, and amortize such costs in a manner consistent with the transfer to the customer of the associated goods or services. Exelon currently expenses those costs as incurred. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method).
The Registrants are currently assessingcontinue to assess the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosuresdisclosures. In performing this assessment, the Registrants have utilized a project implementation team comprised of both internal and external resources to conduct the following key activities:
Actively participate in the AICPA Power and Utilities Industry Task Force (Industry Task Force) process to identify implementation issues and support the development of related implementation guidance;
Evaluate existing contracts and revenue streams for potential changes in the amounts and timing of recognizing revenues under the new guidance;
Evaluate and select the transition method; and
Develop and implement the approach and process for complying with the new revenue recognition disclosure requirements.
While there continues to be some ongoing activities in all of these areas, the Registrants have substantially completed the evaluation of their collective contracts and revenue streams, as well as the evaluation of the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
transition method. Based on the work completed thus far, the Registrants have reached the following preliminary conclusions:
The Registrants expect to apply the new guidance using the full retrospective method, however this conclusion could change based on the outcome of open implementation issues discussed below;
The Registrants currently anticipate that they will use to adopt the guidance. Exelon is considering the impactsimplementation of the new guidance will not have a material impact on itsthe amount and timing of revenue recognition; and
The new guidance will result in more detailed disclosures of revenue compared to current guidance.
Notwithstanding the preliminary conclusions noted above, certain implementation issues continue to be debated and worked through the Industry Task Force process that could result in amendments to the standard or implementation guidance that could have a material impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The contributions in aid of construction (CIAC) implementation issue previously disclosed has been resolved, subject to the completion of the public comment period, with the conclusion that CIAC is outside of the scope of ASC 606 and, therefore, the accounting by the Utility Registrants for CIAC will not change as a result of ASC 606. The open implementation issues that could be most impactful to the Registrants include: (1) the ability of the Utility Registrants to recognize revenue for certain contracts where collectability is in question its accounting for contributions in aid of construction,and (2) primarily at Generation, bundled sales contracts and contracts with pricing provisions that may require it to recognizerecognition of revenue at prices other than the contract price (e.g., straight line or estimated future market prices). In addition,As part of the overall implementation project, the Registrants have developed alternative adoption plans that would be implemented in the event the ultimate resolution of the open implementation issues result in significant changes from current revenue recognition practices.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (Issued March 2017): The new standard will require significant changes to the accounting and presentation of pension and OPEB costs at the plan sponsor (i.e., Exelon) level. This guidance requires plan sponsors to separate net periodic pension cost and net periodic OPEB cost (together, net benefit cost) into the service cost component and other components; service cost will be required to capitalize costs to acquire new contracts, whereas Exelon currently expenses those costspresented as incurred. The guidance is effective for annual reporting periods beginning on or after December 15, 2017, with the option to early adopt the standard for annual periods beginning on or after December 15, 2016. The Registrants do not plan to early adopt the standard. In March 2016, the FASB issued a final amendment to clarify the implementation guidance for principal versus agent considerations and in April 2016 issued a final amendment to clarify the guidance related to identifying performance obligationspart of income from operations and the accountingother components will be classified outside of income from operations on the Consolidated Statements of Operations and Comprehensive Income. Additionally, service cost is the only component eligible for licensescapitalization (whereas under current GAAP, all components of intellectual property. The Registrants do not expect significant impacts based on these updates. In May 2016, the FASB issued a final amendment regarding narrow scope improvementsnet benefit cost are classified as compensation cost and practical expedients. The Registrants are eligible for capitalization).
Exelon is currently assessingevaluating the impact of this update.standard, including coordinating with its industry group and advisors. Generation, ComEd, PECO, BGE, BSC, PHI, Pepco, DPL, ACE and PHISCO participate in Exelon’s single employer plan and apply multi-employer accounting. Exelon is currently evaluating how the new standard will impact accounting and financial reporting for these registrants.
The standard will be effective January 1, 2018 and requires retrospective adoption for the presentation of the service cost component and the other components of net benefit cost and prospective adoption for the capitalization of only the service cost component of net benefit cost. Exelon will not early adopt this standard.
Leases
In (Issued February 2016, the FASB issued authoritative guidance to increase2016): Increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The guidance requires lessees to recognize both theright-of-use assets and lease liabilities in the balance sheet for most leases, whereas today only financing type lease liabilities (capital leases) are recognized in the balance sheet. This is expected to require significant changes to systems, processes and procedures in order to
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
recognize and measure leases recorded on the balance sheet that are currently classified as operating leases. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from current GAAP. The accounting applied by a lessor is largely unchanged from that applied under current GAAP. The standard is effective for fiscal years beginning after December 15, 2018 with2018. Early adoption is permitted, however the Registrants do not expect to early adoption permitted.adopt the standard. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. Refer to Note 24 — Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements in the Exelon 2016 Form10-K for additional information regarding operating leases.
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 asheld-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects the entity’s current estimate of credit losses expected to be incurred over the life of the financial instrument. The Registrants are currently assessingstandard does not make changes to the impacts thisexisting impairment models fornon-financial assets such as fixed assets, intangibles and goodwill. The standard will be effective January 1, 2020 and, for most debt instruments, requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption.
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, may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as wellgoodwill impairment will be measured as the potentialamount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. Exelon, Generation, ComEd, PHI, and DPL have goodwill as of March 31, 2017. This updated guidance is not currently expected to impact the Registrants’ financial reporting. The standard is effective January 1, 2020, with early adopt the guidance.adoption permitted, and must be adopted on a prospective basis.
Clarifying the Definition of a Business (issued January 2017): Clarifies the definition of a business with the objective of addressing whether acquisitions should be accounted for as acquisitions of assets or as acquisitions of businesses. If substantially all the fair value of the assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities is not a business. If the fair value of the assets acquired is not concentrated in a single identifiable asset or a group of similar identifiable assets, then an entity must evaluate whether an input and a substantive process exist, which together significantly contribute to the ability to produce outputs. The standard also revises the definition of outputs to focus on goods and services to customers. The standard could result in more acquisitions being accounted for as asset acquisitions. The standard will be effective January 1, 2018 and will be applied prospectively.
Intra-Entity Transfers of Assets Other Than Inventory
In (Issued October 2016, the FASB issued authoritative guidance which instructs2016): Requires entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs (compared to current GAAP which prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party). The standard is effective for fiscal years beginning after December 15, 2017 with early adoption permitted. The guidance is required to be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
period of adoption. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated StatementsStatement of Cash Flows and disclosures as well as the potential to early adopt the guidance.
Flows: Classification of Certain Cash Receipts and Cash Payments (Issued August 2016) and Restricted Cash (Issued November 2016):
In August 2016, the FASB issued authoritative guidance intended to addtwo standards impacting the Statement of Cash Flows. The first adds or clarifyclarifies guidance on the classification of certain cash receipts and payments on the statement of cash flows. The new guidance addresses cash flows related to the following:as follows: debt prepayment or extinguishment costs, settlement ofzero-coupon bonds, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and bank-owned life insurance policies, distributions received from equity method investees, beneficial interest in securitization transactions, and the application of the predominance principle to separately identifiable cash flows. The standard is effectivesecond states that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling thebeginning-of-period andend-of-period total amounts shown on the statement of cash flows (instead of being presented as cash flow activities). Exelon will adopt both standards on January 1, 2018 with early adoption permitted. The guidance must be applied on a retrospective basis. The Registrants are currently assessingAdoption of the impacts this guidance may havesecond standard will result in a change in presentation of restricted cash on their Consolidated Statementsthe face of the Statement of Cash Flows.
Impairment of Financial Instruments
In June 2016,Flows; otherwise the FASB issued authoritative guidanceRegistrants expect that adds an impairment model to U.S. GAAP called the Current Expected Credit Loss (CECL) model for financial instruments within the scopeadoption of the guidance which includes loans, trade receivables, debt securities classified as held-to-maturity and net investments in leases recognized by a lessor. Underwill have insignificant impacts on the new guidance, on initial recognition and at each reporting period, an entity would be required to recognize an allowance that reflects the entity’s current estimate of credit losses expected to be incurred over the life of the financial instrument. An entity must consider all available relevant information when estimating expected credit losses. Historical charge-off rates may be used as a starting point for determining expected credit losses; however, the entity must also evaluate how conditions that existed during the historical charge-off period may differ from its current expectations and accordingly revise its estimate of expected credit losses. The standard does not make changes to the existing impairment models for non-financial assets such as fixed assets, intangibles and goodwill. The standard will be effective January 1, 2020. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income,Registrants’ Consolidated Statements of Cash Flows and disclosures.
Improvements to Employee Share-Based Payment Accounting
In March 2016, the FASB issued authoritative guidance intended to simplify various aspects to how share-based payment awards to employees are accounted for and presented in the financial statements. The new guidance eliminates additional paid-in capital pools and requires excess tax benefits and tax deficiencies to be recorded in the Statement of Operations and Comprehensive Income. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted if all provisions are adopted within the same period. The guidance is required to be applied on either a prospective, modified retrospective, or retrospective basis depending on the provisions applied. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance.
Simplifying the Transition to the Equity Method of Accounting
In March 2016, the FASB issued authoritative guidance eliminating the requirement to retroactively adopt the equity method of accounting as a result of an increase in the level ownership or degree of influence of an
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
existing investment. The guidance now requires an investor to add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for the equity method of accounting. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance.
Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships
In March 2016, the FASB issued authoritative guidance which clarifies that a change in the counterparty of a derivative contract does not, in and of itself, require dedesignation of that hedge accounting relationship as long as all of the other hedge accounting criteria are met. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. Entities have the option to adopt this standard on a prospective basis to new derivative contract novations or on a modified retrospective basis. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the transition method and the potential to early adopt the guidance.
Contingent Put and Call Options in Debt Instruments
In March 2016, the FASB issued authoritative guidance which simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. The guidance clarifies that a contingent put or call option embedded in a debt instrument would be evaluated for possible separate accounting as a derivative instrument without regard to the nature of the exercise contingency. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied on a modified retrospective basis to all existing and future debt instruments. The Registrants do not expect that this guidance will have a significant impact on Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures and are currently assessing the potential to early adopt the guidance.
Recognition and Measurement of Financial Assets and Financial Liabilities
In (Issued January 2016, the FASB issued authoritative guidance which2016): (i) requiresRequires all investments in equity securities, including other ownership interests such as partnerships, unincorporated joint ventures and limited liability companies, to be carried at fair value through net income, (ii) requires an incremental recognition and disclosure requirement related to the presentation of fair value changes of financial liabilities for which the fair value option has been elected, (iii) amends several disclosure requirements, including the methods and significant assumptions used to estimate fair value or a description of the changes in the methods and assumptions used to estimate fair value, and (iv) requires disclosure of the fair value of financial assets and liabilities measured at amortized cost at the amount that would be received to sell the asset or paid to transfer the liability. The standard is effective for fiscal years beginning after December 15, 2017 with early adoption permitted. The guidance is required to be applied retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Simplifying the Measurement of Inventory
In July 2015, the FASB issued authoritative guidance that requires inventory to be measured at the lower of cost or net realizable value. The new guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This definition is consistent with existing authoritative guidance. Current guidance requires inventory to be measured at the lower of cost or market where market could be replacement cost, net realizable value or net realizable value less an approximately normal profit margin. The guidance is effective for periods beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied prospectively. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance.
3. Variable Interest Entities (All Registrants)
A VIE is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has the power to direct the activities that most significantly affect the entity’s economic performance.
At September 30,March 31, 2017 and December 31, 2016, Exelon, Generation, BGE, PHI and ACE collectively consolidated nine VIEs or VIE groups, for which the applicable Registrant was the primary beneficiary. At December 31, 2015, Exelon, Generation and BGE collectively had seven consolidated VIEs or VIE groups and PHI and ACE collectively had one consolidated VIEbeneficiary (see Consolidated Variable Interest Entities below). As of September 30, 2016March 31, 2017 and December 31, 2015,2016, Exelon and Generation collectively had significant interests in nineseven and eight, respectively, other VIEs respectively, for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary ((see Unconsolidated Variable Interest Entities below).
Consolidated Variable Interest Entities
In June 2015, 2015 ESA Investco, LLC, then a wholly owned subsidiary of Generation, entered into an arrangement to purchase a 90% equity interest and 99% of the tax attributes of another distributed energy company. In November 2015, Generation sold 69% of its equity interest in 2015 ESA Investco, LLC to a tax equity investor. Generation and the tax equity investor will contribute up to a total of $250 million of equity incrementally from inception through December 2016 in proportion to their ownership interests, which equates up to approximately $172 million for the tax equity investor and up to $78 million for Generation (see Note 18 — Commitments and Contingencies for more details). The investment in the distributed energy company was evaluated, and it was determined to be a VIE for which Generation is not the primary beneficiary (see additional details in the Unconsolidated Variable Interest Entities section below). As of December 31, 2015, Generation consolidated 2015 ESA Investco, LLC under the voting interest model. However, pursuant to the new consolidation guidance effective as of January 1, 2016 for the Registrants, 2015 ESA Investco, LLC meets the definition of a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. (For additional details related to the new consolidation guidance, see Note 2 — New Accounting Pronouncements.) Under VIE guidance, Generation is the primary beneficiary; therefore, the entity continues to be consolidated.
Exelon’s, Generation’s, BGE’s, PHI’s and ACE’s consolidated VIEs consist of:
A retail gas group formed by Generation to enter into a collateralized gas supply agreement with a third-party gas supplier,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
a group of solar project limited liability companies formed by Generation to build, own and operate solar power facilities,
several wind project companies designed by Generation to develop, construct and operate wind generation facilities,
a group of companies formed by Generation to build, own and operate other generating facilities,
certain retail power and gas companies for which Generation is the sole supplier of energy,
CENG,
2015 ESA Investco, LLC, a company that holds an equity method investment in a distributed energy company,
BondCo, a special purpose bankruptcy remote limited liability company formed by BGE to acquire, hold, issue and service bonds secured by rate stabilization property, and
ATF, 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.
As of September 30, 2016March 31, 2017 and December 31, 2015,2016, ComEd, PECO, Pepco and DPL did not have any material consolidated VIEs.
As of September 30, 2016March 31, 2017 and December 31, 2015,2016, Exelon, Generation, BGE, PHI and ACE provided the following support to their respective consolidated VIEs:
Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance of the solar and wind power facilities and there is limited recourse to Generation related to certain solar and wind entities.
Generation provides approximately $27 million in credit support for the retail power and gas companies for which Generation is the sole supplier of energy.
Generation provides a $75 million parental guarantee to a third-party gas supplier and provides limited recourse to other third-party gas suppliers and customers in support of its retail gas group.
Generation provides operating and capital funding to the other generating facilities for ongoing construction, operations and maintenance and provides a parental guarantee of up to $275 million in support of the payment obligations related to the Engineering, Procurement and Construction contract in support of one of its other generating facilities.
Generation and Exelon, where indicated, provide the following support to CENG (see Note 5 —Investment— Investment in Constellation Energy Nuclear Group, LLC and Note 2627 — Related Party Transactions of the Exelon 20152016 Form10-K for additional information regarding Generation’s and Exelon’s transactions with CENG):
under the NOSA, Generation conducts all activities related to the operation of the CENG nuclear generation fleet owned by CENG subsidiaries (the CENG fleet) and provides corporate and administrative services for the remaining life and decommissioning of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF,
under the Power Services Agency Agreement (PSAA), Generation provides scheduling, asset management, and billing services to the CENG fleet for the remaining operating life of the CENG nuclear plants,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
under power purchase agreements with CENG, Generation purchased or will purchase 50.01% of the available output generated by the CENG nuclear plants not subject to other contractual agreements from January 2015 through the end of the operating life of each respective plant. However, pursuant to amendments dated March 31, 2015, the energy obligations under the Ginna Nuclear Power Plant (Ginna) PPAs have been suspended during the term of the Reliability Support Services Agreement (RSSA) (see Note 5 — Regulatory Matters for additional details),
Generation provided a $400 million loan to CENG. As of September 30, 2016,March 31, 2017, the remaining obligation is $312$320 million, including accrued interest, which reflects the principal payment made in January 2015,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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 —Commitments17 — Commitments and Contingencies for more details),
in connection with CENG’s severance obligations, Generation has agreed to reimburse CENG for a total of approximately $6 million of the severance benefits paid or to be paid in 2014 through 2016. As of September 30, 2016, there was no remaining obligation,
Generation and EDF share in the $637 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance,
Generation provides a guarantee of approximately $8 million associated with hazardous waste management facilities and underground storage tanks. In addition, EDF executed a reimbursement agreement that provides reimbursement to Exelon for 49.99% of any amounts paid by Generation under this guarantee,
Generation and EDF are the members-insured with Nuclear Electric Insurance Limited and have assigned the loss benefits under the insurance and the NEIL premium costs to CENG and guarantee the obligations of CENG under these insurance programs in proportion to their respective member interests (see Note 1817 — Commitments and Contingencies for more details), 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.
Generation provides approximately $16 million in credit support for the retail power and gas companies for which Generation is the sole supplier of energy.
Generation provides a $75 million parental guarantee to a third-party gas supplier and provides limited recourse to other third-party gas suppliers and customers in support of its retail gas group.
Generation provides operating and capital funding to the other generating facilities for ongoing construction, operations and maintenance and provides a parental guarantee of up to $275 million in support of the payment obligations related to the Engineering, Procurement and Construction contract in support of one of its other generating facilities.
In the case of BondCo, BGE is required to remit all payments it receives from all residential customers throughnon-bypassable, rate stabilization charges to BondCo. During the three and nine months ended September 30,March 31, 2017 and 2016, BGE remitted $27$19 million and $64$20 million to BondCo, respectively. During the three and nine months ended September 30, 2015, BGE remitted $21 million and $63 million to BondCo, respectively.
In the case of ATF, 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 anon-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. During the three and nine months ended September 30,March 31, 2017 and 2016, ACE transferred $20$19 million and $47$14 million to ATF, respectively. During the three and nine months ended September 30, 2015, ACE transferred $18 million and $45 million to ATF, respectively.
For each of the consolidated VIEs, except as otherwise noted:
the assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Exelon, Generation, BGE, PHI and ACE did not provide any additional material financial support to the VIEs;
Exelon, Generation, BGE, PHI and ACE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
the creditors of the VIEs did not have recourse to Exelon’s, Generation’s, BGE’s, PHI’s or ACE’s general credit.
The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants’ consolidated financial statements at September 30, 2016March 31, 2017 and December 31, 20152016 are as follows:
September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Successor | Predecessor | Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon(a)(b) | Generation | BGE | PHI(b) | ACE | Exelon(a) | Generation | BGE | PHI | ACE | Exelon(a) | Generation | BGE | PHI(a) | ACE | Exelon(a)(b) | Generation | BGE | PHI(a) | ACE | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Current assets | $ | 914 | $ | 849 | $ | 44 | $ | 20 | $ | 15 | $ | 909 | $ | 881 | $ | 23 | $ | 12 | $ | 12 | $ | 1,018 | $ | 965 | $ | 42 | $ | 11 | $ | 7 | $ | 954 | $ | 916 | $ | 23 | $ | 14 | $ | 9 | ||||||||||||||||||||||||||||||||||||||||||||
Noncurrent assets | 8,235 | 8,201 | 3 | 31 | 19 | 8,009 | 8,004 | 3 | 18 | 18 | 8,891 | 8,855 | 3 | 33 | 23 | 8,563 | 8,525 | 3 | 35 | 23 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total assets | $ | 9,149 | $ | 9,050 | $ | 47 | $ | 51 | $ | 34 | $ | 8,918 | $ | 8,885 | $ | 26 | $ | 30 | $ | 30 | $ | 9,909 | $ | 9,820 | $ | 45 | $ | 44 | $ | 30 | $ | 9,517 | $ | 9,441 | $ | 26 | $ | 49 | $ | 32 | ||||||||||||||||||||||||||||||||||||||||||||
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Current liabilities | $ | 569 | $ | 439 | $ | 84 | 45 | $ | 40 | $ | 473 | $ | 387 | $ | 81 | $ | 48 | $ | 48 | $ | 871 | $ | 791 | $ | 42 | 38 | $ | 34 | $ | 885 | $ | 802 | $ | 42 | $ | 42 | $ | 37 | ||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent liabilities | 3,090 | 2,979 | — | 111 | 99 | 2,927 | 2,884 | 41 | 124 | 124 | 2,745 | 2,654 | — | 91 | 81 | 2,713 | 2,612 | — | 101 | 89 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total liabilities | $ | 3,659 | $ | 3,418 | $ | 84 | $ | 156 | $ | 139 | $ | 3,400 | $ | 3,271 | $ | 122 | $ | 172 | $ | 172 | $ | 3,616 | $ | 3,445 | $ | 42 | $ | 129 | $ | 115 | $ | 3,598 | $ | 3,414 | $ | 42 | $ | 143 | $ | 126 | ||||||||||||||||||||||||||||||||||||||||||||
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(a) | Includes certain purchase accounting adjustments not pushed down to the |
(b) | Includes certain purchase accounting adjustments not pushed down to the |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Assets and Liabilities of Consolidated VIEs
Included within the balances above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors, or beneficiaries, do not have recourse to the general credit of the Registrants. As of September 30, 2016March 31, 2017 and December 31, 2015,2016, these assets and liabilities primarily consisted of the following:
September 30, 2016 | December 31, 2015 | |||||||||||||||||||||||||||||||||||||||||
Exelon(a)(b) | Generation | BGE | Successor PHI(b) | ACE | Exelon(a) | Generation | BGE | Predecessor PHI | ACE | |||||||||||||||||||||||||||||||||
Cash and cash equivalents | $ | 160 | $ | 160 | $ | — | $ | — | $ | — | $ | 164 | $ | 164 | $ | — | $ | — | $ | — | ||||||||||||||||||||||
Restricted cash | 101 | 43 | 44 | 15 | 15 | 100 | 77 | 23 | 12 | 12 | ||||||||||||||||||||||||||||||||
Accounts receivable, net | ||||||||||||||||||||||||||||||||||||||||||
Customer | 264 | 264 | — | — | — | 219 | 219 | — | — | — | ||||||||||||||||||||||||||||||||
Other | 42 | 42 | — | — | — | 43 | 43 | — | — | — | ||||||||||||||||||||||||||||||||
Mark-to-market derivatives assets | 49 | 49 | — | — | — | 140 | 140 | — | — | — | ||||||||||||||||||||||||||||||||
Inventory | ||||||||||||||||||||||||||||||||||||||||||
Materials and supplies | 192 | 192 | — | — | — | 181 | 181 | — | — | — | ||||||||||||||||||||||||||||||||
Other current assets | 58 | 51 | — | 5 | — | 35 | 30 | — | — | — | ||||||||||||||||||||||||||||||||
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Total current assets | 866 | 801 | 44 | 20 | 15 | 882 | 854 | 23 | 12 | 12 | ||||||||||||||||||||||||||||||||
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Property, plant and equipment, net | 5,139 | 5,139 | — | — | — | 5,160 | 5,160 | — | — | — | ||||||||||||||||||||||||||||||||
Nuclear decommissioning trust funds | 2,173 | 2,173 | — | — | — | 2,036 | 2,036 | — | — | — | ||||||||||||||||||||||||||||||||
Goodwill | 47 | 47 | — | — | — | 47 | 47 | — | — | — | ||||||||||||||||||||||||||||||||
Mark-to-market derivatives assets | 32 | 32 | — | — | — | 53 | 53 | — | — | — | ||||||||||||||||||||||||||||||||
Other noncurrent assets | 257 | 223 | 3 | 31 | 19 | 90 | 85 | 3 | 18 | 18 | ||||||||||||||||||||||||||||||||
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Total noncurrent assets | 7,648 | 7,614 | 3 | 31 | 19 | 7,386 | 7,381 | 3 | 18 | 18 | ||||||||||||||||||||||||||||||||
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Total assets | $ | 8,514 | $ | 8,415 | $ | 47 | $ | 51 | $ | 34 | $ | 8,268 | $ | 8,235 | $ | 26 | $ | 30 | $ | 30 | ||||||||||||||||||||||
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Long-term debt due within one year | $ | 191 | $ | 64 | $ | 81 | $ | 43 | $ | 38 | $ | 111 | $ | 27 | $ | 79 | $ | 46 | $ | 46 | ||||||||||||||||||||||
Accounts payable | 201 | 201 | — | — | — | 216 | 216 | — | — | — | ||||||||||||||||||||||||||||||||
Accrued expenses | 102 | 98 | 2 | 2 | 2 | 115 | 113 | 2 | 2 | 2 | ||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities | 24 | 24 | — | — | — | 5 | 5 | — | — | — | ||||||||||||||||||||||||||||||||
Unamortized energy contract liabilities | 14 | 14 | — | — | — | 12 | 12 | — | — | — | ||||||||||||||||||||||||||||||||
Other current liabilities | 34 | 34 | — | — | — | 13 | 13 | — | — | — | ||||||||||||||||||||||||||||||||
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Total current liabilities | 566 | 435 | 83 | 45 | 40 | 472 | 386 | 81 | 48 | 48 | ||||||||||||||||||||||||||||||||
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Long-term debt | 661 | 550 | — | 111 | 99 | 666 | 623 | 41 | 124 | 124 | ||||||||||||||||||||||||||||||||
Asset retirement obligations | 2,070 | 2,070 | — | — | — | 1,999 | 1,999 | — | — | — | ||||||||||||||||||||||||||||||||
Pension obligation(c) | 9 | 9 | — | — | — | 9 | 9 | — | — | — | ||||||||||||||||||||||||||||||||
Unamortized energy contract liabilities | 26 | 26 | — | — | — | 39 | 39 | — | — | — | ||||||||||||||||||||||||||||||||
Other noncurrent liabilities | 106 | 106 | — | — | — | 79 | 79 | — | — | — | ||||||||||||||||||||||||||||||||
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Total noncurrent liabilities | 2,872 | 2,761 | — | 111 | 99 | 2,792 | 2,749 | 41 | 124 | 124 | ||||||||||||||||||||||||||||||||
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Total liabilities | $ | 3,438 | $ | 3,196 | $ | 83 | $ | 156 | $ | 139 | $ | 3,264 | $ | 3,135 | $ | 122 | $ | 172 | $ | 172 | ||||||||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
March 31, 2017 | December 31, 2016 | |||||||||||||||||||||||||||||||||||||||
Successor | Successor | |||||||||||||||||||||||||||||||||||||||
Exelon(a) | Generation | BGE | PHI(a) | ACE | Exelon(a)(b) | Generation | BGE | PHI (a) | ACE | |||||||||||||||||||||||||||||||
Cash and cash equivalents | $ | 199 | $ | 199 | $ | — | $ | — | $ | — | $ | 150 | $ | 150 | $ | — | $ | — | $ | — | ||||||||||||||||||||
Restricted cash | 124 | 75 | 42 | 7 | 7 | 59 | 27 | 23 | 9 | 9 | ||||||||||||||||||||||||||||||
Accounts receivable, net | ||||||||||||||||||||||||||||||||||||||||
Customer | 347 | 347 | — | — | — | 371 | 371 | — | — | — | ||||||||||||||||||||||||||||||
Other | 23 | 23 | — | — | — | 48 | 48 | — | — | — | ||||||||||||||||||||||||||||||
Mark-to-market derivatives assets | 41 | 41 | — | — | — | 31 | 31 | — | — | — | ||||||||||||||||||||||||||||||
Inventory | ||||||||||||||||||||||||||||||||||||||||
Materials and supplies | 191 | 191 | — | — | — | 199 | 199 | — | — | — | ||||||||||||||||||||||||||||||
Other current assets | 58 | 54 | — | 4 | — | 50 | 44 | — | 5 | — | ||||||||||||||||||||||||||||||
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Total current assets | 983 | 930 | 42 | 11 | 7 | 908 | 870 | 23 | 14 | 9 | ||||||||||||||||||||||||||||||
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Property, plant and equipment, net | 5,425 | 5,425 | — | — | — | 5,415 | 5,415 | — | — | — | ||||||||||||||||||||||||||||||
Nuclear decommissioning trust funds | 2,286 | 2,286 | — | — | — | 2,185 | 2,185 | — | — | — | ||||||||||||||||||||||||||||||
Goodwill | 47 | 47 | — | — | — | 47 | 47 | — | — | — | ||||||||||||||||||||||||||||||
Mark-to-market derivatives assets | 57 | 57 | — | — | — | 23 | 23 | — | — | — | ||||||||||||||||||||||||||||||
Other noncurrent assets | 350 | 314 | 3 | 33 | 23 | 315 | 277 | 3 | 35 | 23 | ||||||||||||||||||||||||||||||
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Total noncurrent assets | 8,165 | 8,129 | 3 | 33 | 23 | 7,985 | 7,947 | 3 | 35 | 23 | ||||||||||||||||||||||||||||||
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Total assets | $ | 9,148 | $ | 9,059 | $ | 45 | $ | 44 | $ | 30 | $ | 8,893 | $ | 8,817 | $ | 26 | $ | 49 | $ | 32 | ||||||||||||||||||||
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Long-term debt due within one year | $ | 237 | $ | 159 | $ | 41 | $ | 37 | $ | 33 | $ | 181 | $ | 99 | $ | 41 | $ | 40 | $ | 35 | ||||||||||||||||||||
Accounts payable | 275 | 275 | — | — | — | 269 | 269 | — | — | — | ||||||||||||||||||||||||||||||
Accrued expenses | 85 | 83 | 1 | 1 | 1 | 119 | 116 | 1 | 2 | 2 | ||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities | 18 | 18 | — | — | — | 60 | 60 | — | — | — | ||||||||||||||||||||||||||||||
Unamortized energy contract liabilities | 16 | 16 | — | — | — | 15 | 15 | — | — | — | ||||||||||||||||||||||||||||||
Other current liabilities | 11 | 11 | — | — | — | 30 | 30 | — | — | — | ||||||||||||||||||||||||||||||
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Total current liabilities | 642 | 562 | 42 | 38 | 34 | 674 | 589 | 42 | 42 | 37 | ||||||||||||||||||||||||||||||
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Long-term debt | 626 | 535 | — | 91 | 81 | 641 | 540 | — | 101 | 89 | ||||||||||||||||||||||||||||||
Asset retirement obligations | 1,929 | 1,929 | — | — | — | 1,904 | 1,904 | — | — | — | ||||||||||||||||||||||||||||||
Pension obligation(c) | 8 | 8 | — | — | — | 9 | 9 | — | — | — | ||||||||||||||||||||||||||||||
Unamortized energy contract liabilities | 18 | 18 | — | — | — | 22 | 22 | — | — | — | ||||||||||||||||||||||||||||||
Other noncurrent liabilities | 122 | 122 | — | — | — | 106 | 106 | — | — | — | ||||||||||||||||||||||||||||||
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Total noncurrent liabilities | 2,703 | 2,612 | — | 91 | 81 | 2,682 | 2,581 | — | 101 | 89 | ||||||||||||||||||||||||||||||
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Total liabilities | $ | 3,345 | $ | 3,174 | $ | 42 | $ | 129 | $ | 115 | $ | 3,356 | $ | 3,170 | $ | 42 | $ | 143 | $ | 126 | ||||||||||||||||||||
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(a) | Includes certain purchase accounting adjustments not pushed down to the |
(b) | Includes certain purchase accounting adjustments not pushed down to the |
(c) | Includes the CNEG retail gas pension obligation, which is presented as a net asset balance within the Prepaid pension asset line item on Generation’s |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Unconsolidated Variable Interest Entities
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 on 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. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.
The Registrants’ unconsolidated VIEs consist of:
Energy purchase and sale agreements with VIEs for which Generation has concluded that consolidation is not required.
Asset sale agreement with ZionSolutions, LLC and EnergySolutions, Inc. in which Generation has a variable interest but has concluded that consolidation is not required.
Equity investments in energy development companies, distributed energy companies and energy generating facilities for which Generation has concluded that consolidation is not required.
As of September 30, 2016March 31, 2017 and December 31, 2015,2016, Exelon and Generation had significant unconsolidated variable interests in nineseven and eight VIEs, respectively for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity investments and certain commercial agreements. The decrease in the number of unconsolidated VIEs is due to the sale of an equity investment in an energy generating facility. Exelon and Generation only include unconsolidated VIEs that are individually material in the tables below. However, Generation has several individually immaterial VIEs that in aggregate represent a total investment of $20$16 million. These immaterial VIEs are equity and debt securities in energy development companies. The maximum exposure to loss related to these securities is limited to the $20$16 million included in Investments on Exelon’s and Generation’s Consolidated Balance Sheets. The risk of a loss was assessed to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.
In July 2014, Generation entered into an arrangement to purchase a 90% equity interest and 90% of the tax attributes of a distributed energy company. Generation’s total equity commitment in this arrangement was $91 million and was paid incrementally over an approximate two year period (see Note 18 — Commitments and Contingencies for additional details). This arrangement did not meet the definition of a VIE and was recorded as an equity method investment. However, pursuant to the new consolidation guidance effective as of January 1, 2016 for the Registrants, the distributed energy company meets the definition of a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick out rights of the general partner. (For additional details related to the new consolidation guidance, see Note 2 — New Accounting Pronouncements.) Generation is not the primary beneficiary; therefore, the investment continues to be recorded using the equity method.
In June 2015, 2015 ESA Investco, LLC, then a wholly owned subsidiary of Generation, entered into an arrangement to purchase a 90% equity interest and 99% of the tax attributes of a distributed energy company,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
which is an unconsolidated VIE. Separate from the equity investment, Generation provided $27 million in cash to the other (10%) equity holder in the distributed energy company in exchange for a convertible promissory note. In November 2015, Generation sold 69% of its equity interest in 2015 ESA Investco, LLC to a tax equity investor. Generation and the tax equity investor will contribute up tocontributed a total of $250$227 million of equity incrementally from inception through December 2016the first quarter of 2017 in proportion of their ownership interests, which equates up to approximately $172 million for the tax equity investor and up to $78 million for Generation (see Note 18 — Commitments and Contingencies for additional details).interests. Generation and the tax equity investor provideprovided a parental guarantee of up to $275 million in proportion to their ownership interests in support of 2015 ESA Investco, LLC’s obligation to make equity contributions to the distributed energy company, whichcompany. As all equity contributions were made as of March 31, 2017, there is an unconsolidated VIE. The investmentno further payment obligation under the parental guarantee.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in the distributed energy company was evaluated and it was determined to be a VIE for which Generation is not the primary beneficiary. See additional details in the Consolidated Variable Interest Entities section above.millions, except per share data, unless otherwise noted)
The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:
September 30, 2016 | Commercial Agreement VIEs | Equity Investment VIEs | Total | |||||||||||||||||||||
March 31, 2017 | Commercial Agreement VIEs | Equity Investment VIEs | Total | |||||||||||||||||||||
Total assets(a) | $ | 586 | $ | 531 | $ | 1,117 | $ | 647 | $ | 541 | $ | 1,188 | ||||||||||||
Total liabilities(a) | 181 | 308 | 489 | 73 | 230 | 303 | ||||||||||||||||||
Exelon’s ownership interest in VIE(a) | — | 193 | 193 | — | 276 | 276 | ||||||||||||||||||
Other ownership interests in VIE(a) | 405 | 34 | 439 | 574 | 36 | 610 | ||||||||||||||||||
Registrants’ maximum exposure to loss: | ||||||||||||||||||||||||
Carrying amount of equity method investments | — | 225 | 225 | — | 279 | 279 | ||||||||||||||||||
Contract intangible asset | 9 | — | 9 | 9 | — | 9 | ||||||||||||||||||
Debt and payment guarantees | — | 3 | 3 | — | — | — | ||||||||||||||||||
Net assets pledged for Zion Station decommissioning(b) | 11 | — | 11 | 7 | — | 7 |
December 31, 2015 | Commercial Agreement VIEs | Equity Investment VIEs | Total | |||||||||||||||||||||
December 31, 2016 | Commercial Agreement VIEs | Equity Investment VIEs | Total | |||||||||||||||||||||
Total assets(a) | $ | 263 | $ | 164 | $ | 427 | $ | 638 | $ | 567 | $ | 1,205 | ||||||||||||
Total liabilities(a) | 22 | 125 | 147 | 215 | 287 | 502 | ||||||||||||||||||
Exelon’s ownership interest in VIE(a) | — | 11 | 11 | — | 248 | 248 | ||||||||||||||||||
Other ownership interests in VIE(a) | 241 | 28 | 269 | 423 | 32 | 455 | ||||||||||||||||||
Registrants’ maximum exposure to loss: | ||||||||||||||||||||||||
Carrying amount of equity method investments | — | 21 | 21 | — | 264 | 264 | ||||||||||||||||||
Contract intangible asset | 9 | — | 9 | 9 | — | 9 | ||||||||||||||||||
Debt and payment guarantees | — | 3 | 3 | — | 3 | 3 | ||||||||||||||||||
Net assets pledged for Zion Station decommissioning(b) | 17 | — | 17 | 9 | — | 9 |
(a) | These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. |
(b) | These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
For each of the unconsolidated VIEs, Exelon and Generation has 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. In addition, there are no material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs.
4. Mergers, Acquisitions and Dispositions (Exelon, Generation PHI and Pepco)PHI)
Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)
On March 31, 2017, Generation acquired the 838 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York from Entergy Nuclear FitzPatrick LLC (Entergy) for a total purchase price of $293 million, which consisted of a cash purchase price of $110 million and a net cost reimbursement to and on behalf of Entergy of $183 million. As part of the acquisition agreements, Generation provided nuclear fuel and reimbursed Entergy for incremental costs to prepare for and conduct a plant refueling outage; and Generation reimbursed Entergy for incremental costs to operate and maintain the plant for the period
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
after the refueling outage through the acquisition closing date. These reimbursements covered costs that Entergy otherwise would have avoided had it shut down the plant as originally intended in January 2017. The amounts reimbursed by Generation were offset by FitzPatrick’s electricity and capacity sales revenues for this same post-outage period. As part of the transaction, Generation received the FitzPatrick NDT fund assets and assumed the obligation to decommission FitzPatrick. The NRC license for FitzPatrick expires in 2034. As of March 31, 2017, Generation had remitted purchase price consideration of $302 million (including $248 million of cash and $54 million of nuclear fuel) to and on behalf of Entergy and has $9 million included in Accounts receivable, net — Other on Exelon’s and Generation’s Consolidated Balance Sheets, to be received during the second quarter of 2017.
The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the FitzPatrick acquisition by Generation as of March 31, 2017:
Cash paid for purchase price | $ | 110 | ||
Cash paid for net cost reimbursement | 129 | |||
Nuclear fuel transfer | 54 | |||
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Total consideration transferred | $ | 293 | ||
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Identifiable assets acquired and liabilities assumed | ||||
Current assets | $ | 58 | ||
Property, plant and equipment | 278 | |||
Nuclear decommissioning trust funds | 807 | |||
Other assets(a) | 114 | |||
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Total assets | $ | 1,257 | ||
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Current liabilities | $ | 7 | ||
Asset retirement obligations | 417 | |||
Pension and OPEB obligations | 49 | |||
Deferred income taxes | 144 | |||
Spent nuclear fuel obligation | 110 | |||
Other liabilities | 11 | |||
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Total liabilities | $ | 738 | ||
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Total net identifiable assets, at fair value | $ | 519 | ||
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Bargain purchase gain(after-tax) | $ | 226 | ||
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(a) | Includes a $110 million asset associated with a contractual right to reimbursement from the New York Power Authority (NYPA), a prior owner of FitzPatrick, associated with the DOEone-time fee obligation. See Note24-Commitments and Contingencies of the Exelon 2016 Form10-K for additional background regarding SNF obligations to the DOE. |
Theafter-tax bargain purchase gain of $226 million is included within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and reflects differences in strategies between Generation and Entergy for the intended use and ultimate decommissioning of the plant.
The fair values of FitzPatrick’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices. The valuations performed to assess the fair value of certain assets acquired and liabilities assumed are preliminary. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date; however, Generation expects to finalize these amounts by the end of 2017. The significant assets and liabilities for which preliminary valuation amounts are recognized at March 31, 2017 include the fair value of the decommissioning ARO, pension and OPEB obligations and related deferred tax liabilities. Any changes to the fair value assessments may materially impact the purchase price allocation and the amount of the recorded bargain purchase gain.
For the three months ended March 31, 2017, Exelon and Generation incurred $32 million of merger and integration related costs which are included within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Merger with Pepco Holdings, Inc. (Exelon)
Description of Transaction
On March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub) and Pepco Holdings, Inc. (PHI). As a result of that merger, Merger Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and Exelon Energy Delivery Company, LLC (EEDC), a wholly owned subsidiary of Exelon which also owns Exelon’s interests in ComEd, PECO and BGE (through a special purpose subsidiary in the case of BGE). Following the completion of the PHI Merger, Exelon and PHI completed a series of internal corporate organization restructuring transactions resulting in the transfer of PHI’s unregulated business interests to Exelon and Generation and the transfer of PHI, Pepco, DPL and ACE to a special purpose subsidiary of EEDC.
Regulatory Matters
Approval of the merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments including where applicable: customer rate credits, funding for energy efficiency and delivery system modernization programs, a green sustainability fund, workforce development initiatives, charitable contributions, renewable generation and other required commitments. In addition, the orders approving the merger in Delaware, New Jersey, and Maryland include a “most favored nation” provision which, generally speaking, requires allocation of merger benefits proportionally across all the jurisdictions. In the first quarter of 2016, Exelon estimated and recorded total nominal cost commitments of $508 million, excluding renewable generation commitments (approximately $444 million on a net present value basis, excluding renewable generation commitments and charitable contributions).
During the third and fourth quarters of 2016, Exelon and PHI filed proposals in Delaware, and New Jersey and continued negotiations in Maryland for amounts and allocations reflecting the application of the most favored nation provision, resulting in a total nominal cost of commitments of $513 million, excluding renewable generation commitments (with no change in the(approximately $444 million on a net present value basis amount, excluding renewable generation commitments and charitable contributions). A similar filing will be required in Maryland. These filings which reflect agreements reached with certain parties to the merger proceedings in these jurisdictions. In 2016, the jurisdictions, are subject to regulatory reviewDPSC and approval in each jurisdiction. The Delaware CommissionNJBPU approved the amounts and allocations in Septemberof the additional merger benefits for Delaware and October 2016 andNew Jersey, respectively. On April 12, 2017, the MDPSC issued an order fromapproving the New Jersey BPU is expected inamounts of the fourth quarteradditional merger benefits for Maryland, but amending the proposed allocations of 2016.the benefits. The amended allocations do not have a material effect on any of the Registrants’ financial statements. No changes in commitment cost levels are required in the District of Columbia.
The proposed settlements included certain changes in the amount and mix of previously reported, expected commitment types, resulting in adjustments to the estimated commitment costs recorded by Exelon Corporate and by the individual PHI utility reporting entities such that more commitments are expected to be obligations of Exelon Corporate for energy efficiency, workforce development and other programs as opposed to obligations of PHI, Pepco, DPL and ACE for additional customer rate credits. Specifically, for the three months ended September 30, 2016, Exelon Corporate recorded an increase of $55 million and PHI, Pepco, DPL and ACE recorded decreases of $50 million, $13 million, $27 million and $10 million, respectively, in Operating and maintenance expense.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following amounts were recognized asrepresent total commitment costs in Operatingfor Exelon, PHI, Pepco, DPL and maintenance expense in Exelon’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income forACE that have been recorded since the nine months ended September 30, 2016 and PHI’s successor period:acquisition date:
Successor | ||||||||||||||||||||||||||||||||||||||||||||||||
Expected Payment Period | Successor | |||||||||||||||||||||||||||||||||||||||||||||||
Description | Pepco(a) | DPL(a) | ACE(a) | PHI(a) | Exelon(a) | Expected Payment Period | Pepco | DPL | ACE | PHI | Exelon | |||||||||||||||||||||||||||||||||||||
Rate credits | 2016 — 2017 | $ | 91 | $ | 58 | $ | 101 | $ | 250 | $ | 250 | 2016 — 2017 | $ | 91 | $ | 66 | $ | 101 | $ | 258 | $ | 258 | ||||||||||||||||||||||||||
Energy efficiency | 2016 — 2021 | — | — | — | — | 120 | 2016 — 2021 | — | — | — | — | 122 | ||||||||||||||||||||||||||||||||||||
Charitable contributions | 2016 — 2026 | 28 | 12 | 10 | 50 | 50 | 2016 — 2026 | 28 | 12 | 10 | 50 | 50 | ||||||||||||||||||||||||||||||||||||
Delivery system modernization | Q2 2016 | — | — | — | — | 22 | Q2 2016 | — | — | — | — | 22 | ||||||||||||||||||||||||||||||||||||
Green sustainability fund | Q2 2016 | — | — | — | — | 14 | Q2 2016 | — | — | — | — | 14 | ||||||||||||||||||||||||||||||||||||
Workforce development | 2016 — 2020 | — | — | — | — | 24 | 2016 — 2020 | — | — | — | — | 17 | ||||||||||||||||||||||||||||||||||||
Other | 7 | 7 | — | 14 | 33 | 7 | 7 | — | 14 | 30 | ||||||||||||||||||||||||||||||||||||||
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Total | $ | 126 | $ | 77 | $ | 111 | $ | 314 | $ | 513 | $ | 126 | $ | 85 | $ | 111 | $ | 322 | $ | 513 | ||||||||||||||||||||||||||||
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Pursuant to the orders approving the merger, Exelon made $73 million, $46 million and $49 million of equity contributions to Pepco, DPL and ACE, respectively, in the second quarter of 2016 to fund theafter-tax amounts of the customer bill credit and the customer base rate credit commitments.
In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new generation in Maryland, District of Columbia, and Delaware, 27 MWs of which are expected to be completed by 2018. These investments are expected to total approximately $137 million, are expected to be primarily capital in nature, and will generate future earnings at Exelon and Generation. The actual cost of investment in new generation may differ depending on the result of final negotiations and application of the most favored nation provision. Investment costs will be recognized as incurred and recorded on Exelon’s and Generation’s financial statements. Exelon has also committed to purchase 100 MWs of wind energy in PJM, to procure 120 MWs of wind RECs for the purpose of meeting Delaware’s renewable portfolio standards, and to maintain and promote energy efficiency and demand response programs in the PHI jurisdictions.
Pursuant to the various jurisdictions’ merger approval conditions, over specified periods Pepco, DPL and ACE are not permitted to reduce employment levels due to involuntary attrition associated with the merger integration process and have made other commitments regarding hiring and relocation of positions.
Exelon was previously named in suits filed in the Delaware Chancery Court alleging that individual directors of PHI breached their fiduciary duties by entering into the merger transaction, and that Exelon aided and abetted the individual directors’ breaches. The suits sought rescission of the merger and unspecified damages and costs. On June 1, 2016, the parties executed a settlement to resolve all claims, subject to the approval of the Delaware Court. A hearing had been scheduled for September 8, 2016 in the Delaware Court to consider whether to approve the settlement. However, on August 19, 2016, the plaintiffs advised Exelon that they had determined to dismiss the case in its entirety and with prejudice. On August 24, 2016, the Delaware Court issued an order approving the dismissal.
In July 2015, the OPC, Public Citizen, Inc., the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed motions to stay the MDPSC order approving the merger and in July and August, Exelon, PHI, the MDPSC, Prince George’s County and Montgomery County filed responses opposing the motions to stay.merger. The Circuit Court judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, CCAN and Public Citizen, Inc. On January 19, 2016, the OPC filed a notice of appeal to the Maryland Court of Special Appeals, and on January 21, the Sierra Club and CCAN filed a notice of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court’s judgment. The OPC and Sierra Club have each filed petitions seeking further review in the Court of Appeals of Maryland. Exelon, along with Prince George’s County and Montgomery County have filed answers opposing those petitions, which Exelon believes the matters are without merit. These appeals are not expected to be resolved any earlier than the first quarter of 2017.
Between March 25, 2016 and April 22, 2016, various parties filed motions with the DCPSC to reconsider its March 23, 2016 order approving the merger. On June 17, 2016, the DCPSC denied all motions. In August 2016, the District of Columbia Office of People’s Counsel, the District of Columbia Government, and Public Citizen jointly with DC Sun each filed petitions for judicial review of the DCPSC’s March 23, 2016 order with the District of Columbia Court of Appeals. On September 9, 2016, the Court consolidated the appeals. AlthoughThe parties have filed briefs and the Court has not yet issued a scheduling order, ascheduled oral argument for May 2. A decision on this matter is not expected untilin the second or third quarter of 2017. Exelon believes the matters are without merit.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Accounting for the Merger Transaction
The total purchase price consideration of approximately $7.1 billion for the PHI Merger consisted of cash paid to PHI shareholders, cash paid for PHI preferred securities and cash paid for PHI stock-based compensation equity awards as follows:
(In millions of dollars, except per share data) | Total Consideration | Total Consideration | ||||||
Cash paid to PHI shareholders at $27.25 per share (254 million shares outstanding at March 23, 2016) | $ | 6,933 | $ | 6,933 | ||||
Cash paid for PHI preferred stock(a) | 180 | 180 | ||||||
Cash paid for PHI stock-based compensation equity awards(b) | 29 | 29 | ||||||
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Total purchase price | $ | 7,142 | $ | 7,142 | ||||
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(a) | As of December 31, 2015, the preferred stock was included in Othernon-current assets on Exelon’s Consolidated Balance Sheets. |
(b) | PHI’s unvested time-based restricted stock units and performance-based restricted stock units issued prior to April 29, 2014 were immediately vested and paid in cash upon the close of the merger. PHI’s remaining unvested time-based restricted stock units as of the close of the merger were cancelled. There were no remaining unvested performance-based restricted stock units as of the close of the merger. |
PHI shareholders received $27.25 of cash in exchange for each share of PHI common stock outstanding as of the effective date of the merger. In connection with the Merger Agreement, Exelon entered into a Subscription Agreement under which it purchased $180 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities of PHI prior to December 31, 2015. On March 23, 2016, the preferred securities were cancelled for no consideration to Exelon, and accordingly, the $180 million cash consideration previously paid to acquire the preferred securities was treated as purchase price consideration.
The preliminary valuations performed in the first quarter of 2016 were updated in the second, third, and fourth quarters of 2016. There were no adjustments to assess the fair value of certain assets acquired and liabilities assumed were considered preliminary as a result of the short time period between the closing of the merger and the end ofpurchase price allocation in the first quarter of 2016. Accounting guidance provides that the allocation of2017 and the purchase price may be modified up to one year from the date of the merger as more informationallocation is obtained about the fair value of assets acquired and liabilities assumed; however, Exelon expects to finalize these amounts by the end of 2016. During the second and third quarters, certain modifications were made to preliminary valuation amounts for acquired property, plant and equipment, unamortized energy contracts, current liabilities, long-term debt,now final.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
deferred income taxes and pension and OPEB liability resulting in a $16 million net decrease to goodwill. The preliminary amounts recognized are subject to further revision to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes to the fair value assessments may affect the purchase price allocation and could potentially impact goodwill.
Exelon applied push-down accounting to PHI, and accordingly, the PHI assets acquired and liabilities assumed were recorded at their estimated fair values on Exelon’s and PHI’s Consolidated Balance Sheets as of March 23, 2016, as follows:
Preliminary Purchase Price Allocation | ||||||||
Purchase Price Allocation(a) | ||||||||
Current assets | $ | 1,441 | $ | 1,441 | ||||
Property, plant and equipment | 11,088 | 11,088 | ||||||
Regulatory assets | 5,015 | 5,015 | ||||||
Other assets | 248 | 248 | ||||||
Goodwill | 4,000 | 4,005 | ||||||
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Total assets | $ | 21,792 | $ | 21,797 | ||||
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Current liabilities | $ | 2,752 | $ | 2,752 | ||||
Unamortized energy contracts | 1,515 | 1,515 | ||||||
Regulatory liabilities | 297 | 297 | ||||||
Long-term debt, including current maturities | 5,636 | 5,636 | ||||||
Deferred income taxes | 3,442 | 3,447 | ||||||
Pension and OPEB liability | 821 | |||||||
Pension and OPEB obligations | 821 | |||||||
Other liabilities | 187 | 187 | ||||||
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Total liabilities | $ | 14,650 | $ | 14,655 | ||||
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Total purchase price | $ | 7,142 | $ | 7,142 | ||||
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(a) | Amounts shown reflect the final purchase price allocation and the correction of a reporting error identified and corrected in the second quarter of 2016. The error had resulted in a gross up of certain assets and liabilities related to legacy PHI intercompany and income tax receivable and payable balances. |
On its successor financial statements, PHI has recorded, beginning March 24, 2016, Membership interest equity of $7.2 billion, which is greater than the total $7.1 billion purchase price, reflecting the impact of a $59 million deferred tax liability recorded only at Exelon Corporate to reflect unitary state income tax consequences of the merger.
The excess of the purchase price over the estimated fair value of the assets acquired and the liabilities assumed totaled $4.0 billion, which was recognized as goodwill by PHI and Exelon at the acquisition date, reflecting the value associated with enhancing Exelon’s regulated utility portfolio of businesses, including the ability to leverage experience and best practices across the utilities and the opportunities for synergies. For purposes of future required impairment assessments, the goodwill has been preliminarily assigned to PHI’s reportable units Pepco, DPL and ACE in the amounts of $1.7 billion, $1.1 billion and $1.2 billion, respectively. None of this goodwill is expected to be tax deductible.
Immediately following closing of the merger, $235 million of net assets included in the table above associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Exelon contributed $163 million of such net assets to Generation.
The fair values of PHI’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows, future market prices and impacts of utility rate regulation. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired.
Through its wholly-owned rate regulated utility subsidiaries, most of PHI’s assets and liabilities are subject tocost-of-service rate regulation. Under such regulation, rates charged to customers are established by a
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Exelon’s and PHI’s carrying amount of goodwill for the nine months ended September 30, 2016 was as follows:
PHI | Exelon(a) | |||||||
Beginning balance, December 31, 2015 | $ | — | $ | 2,672 | ||||
Goodwill from business combination | 4,016 | 4,016 | ||||||
Measurement period adjustments | (16 | ) | (16 | ) | ||||
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Ending balance, September 30, 2016 | $ | 4,000 | $ | 6,672 | ||||
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Through its wholly-owned rate regulated utility subsidiaries, most of PHI’s assets and liabilities are subject to cost-of-service rate regulation. Under such regulation, rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on invested capital, or rate base, generally measured at historical cost. In applying the acquisition method of accounting, for regulated assets and liabilities included in rate base or otherwise earning a return (primarily property, plant and equipment and regulatory assets earning a return), no fair value adjustments were recorded as historical cost is viewed as a reasonable proxy for fair value.
Fair value adjustments were applied to the historical cost bases of other assets and liabilities subject to rate regulation but not earning a return (including debt instruments and pension and OPEB obligations). In these instances, a corresponding offsetting regulatory asset or liability was also established, as the underlying utility asset and liability amounts are recoverable from or refundable to customers at historical cost (and not at fair value) through the rate setting process. Similar treatment was applied for fair value adjustments to record intangible assets and liabilities, such as for electricity and gas energy supply contracts as further described below. Regulatory assets and liabilities established to offset fair value adjustments are amortized in amounts and over time frames consistent with the realization or settlement of the fair value adjustments, with no impact on reported net income. See Note 5 — Regulatory Matters for additional information regarding the fair value of regulatory assets and liabilities established by Exelon and PHI.
Fair value adjustments were recorded at Exelon and PHI for the difference between the contract price and the market price of electricity and gas energy supply contracts of PHI’s wholly-owned rate regulated utility subsidiaries. These adjustments are intangible assets and liabilities classified as unamortized energy contracts on Exelon’s and PHI’s Consolidated Balance Sheets as of September 30, 2016.March 31, 2017. The difference between the contract price and the market price at the acquisition date of the Merger was recognized for each contract as either an intangible asset or liability. In total, Exelon and PHI recorded a net $1.5 billion liability reflectingout-of-the-money contracts. The valuation of the acquired intangible assets and liabilities was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. In certain instances, the valuations were based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates and inputs include forecasted power prices and the discount rate. The unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchase power and fuel expense or Operating revenues, as applicable, over the life of the applicable contract in relation to the present value of the underlying cash flows as of the merger date.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
As mentioned, undercost-of-service rate regulation, rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on invested capital, or rate base, generally measured at historical cost. Historical cost information therefore is the most relevant presentation for the financial statements of PHI’s rate regulated utility subsidiary registrants, Pepco, DPL and ACE. As such, Exelon and PHI did not push-down the application of acquisition accounting to PHI’s utility registrants, and therefore the financial statements of Pepco, DPL and ACE do not reflect the revaluation of any assets and liabilities.
The current impact of PHI, including its unregulated businesses, on Exelon’s Consolidated Statements of Operations and Comprehensive Income includes Operating revenues of $1.4$1.2 billion and Net income of $169$140 million during the three months ended September 30, 2016,March 31, 2017, and Operating revenues of $2.7 billion$107 million and Net loss of $(92)$(315) million during the ninethree months ended September 30,March 31, 2016.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
For the three and nine months ended September 30,March 31, 2017 and 2016, and 2015, the Registrants have recognized costs to achieve the PHI acquisition as follows:
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
Acquisition, Integration and Financing Costs(a) | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||
Exelon(b) | $ | 20 | $ | 22 | $ | 123 | $ | 84 | $ | 9 | $ | 102 | ||||||||||||
Generation | 9 | 10 | 29 | 30 | 9 | 16 | ||||||||||||||||||
ComEd(c) | — | 3 | (6 | ) | 9 | — | (8 | ) | ||||||||||||||||
PECO | 1 | 1 | 3 | 4 | 1 | 2 | ||||||||||||||||||
BGE | 1 | 2 | (3 | ) | 4 | 2 | 2 | |||||||||||||||||
Pepco | 3 | 1 | 26 | 3 | 1 | 27 | ||||||||||||||||||
DPL | 2 | — | 18 | 2 | (7 | ) | 16 | |||||||||||||||||
ACE | 2 | — | 17 | 1 | 1 | 13 |
Successor | Predecessor | Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||
Acquisition, Integration and | Three Months Ended September 30, 2016 | Three Months Ended September 30, 2015 | March 24 to September 30, 2016 | January 1 to March 23, 2016 | Nine Months Ended September 30, 2015 | Three Months Ended March 31, 2017 | March 24, 2016 to March 31, 2016 | January 1, 2016 to March 23, 2016 | ||||||||||||||||||||||||
PHI | $ | 7 | $ | 3 | $ | 63 | $ | 29 | $ | 16 | $ | (5 | ) | $ | 56 | $ | 29 |
(a) | The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above. |
(b) | Reflects costs (benefits) recorded at Exelon related to financing, includingmark-to-market activity on forward-starting interest rate swaps. |
(c) | For the |
(d) | For the three months ended March 31, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, incurred at DPL that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5 — Regulatory Matters for more information. |
Pro-forma Impact of the Merger
The following unaudited pro forma financial information reflects the consolidated results of operations of Exelon as if the merger with PHI had taken place on January 1, 2015. The unaudited pro forma information was calculated after applying Exelon’s accounting policies and adjusting PHI’s results to reflect purchase accounting adjustments.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or the future consolidated results of operations of the combined company.
Three Months Ended September 30, | Nine Months Ended September 30, | Year Ended December 31, | ||||||||||||||||||
2016(a) | 2015(b) | 2016(a) | 2015(b) | 2015(c) | ||||||||||||||||
Total operating revenues | $ | 9,002 | $ | 8,545 | $ | 24,468 | $ | 26,129 | $ | 33,823 | ||||||||||
Net income attributable to common shareholders | 501 | 746 | 1,346 | 2,169 | 2,618 | |||||||||||||||
Basic earnings per share | $ | 0.54 | $ | 0.81 | $ | 1.46 | $ | 2.36 | $ | 2.85 | ||||||||||
Diluted earnings per share | 0.54 | 0.81 | 1.45 | 2.35 | 2.84 |
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Acquisition of ConEdison Solutions (Exelon and Generation)
On September 1, 2016, Generation acquired the competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc. (ConEdison Solutions), a subsidiary of Consolidated Edison, Inc. for a purchase price of $257 million including net working capital of $204 million. The renewable energy, sustainable services and energy efficiency businesses of ConEdison Solutions are excluded from the transaction. As of September 30, 2016, Generation had remitted $235 million to ConEdison Solutions and the remaining balance of $22 million, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets, will be paid during the first quarter of 2017.
The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the ConEdison Solutions acquisition by Generation as of September 1, 2016:
Total consideration transferred | $ | 257 | ||
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Identifiable assets acquired and liabilities assumed | ||||
Working capital assets | $ | 204 | ||
Property, plant and equipment | 2 | |||
Mark-to-market derivative assets | 6 | |||
Unamortized energy contract assets | 100 | |||
Customer relationships | 9 | |||
Other assets | 1 | |||
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Total assets | $ | 322 | ||
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Mark-to-market derivative liabilities | $ | (65 | ) | |
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Total liabilities | $ | (65 | ) | |
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Total net identifiable assets, at fair value | $ | 257 | ||
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Three Months Ended March 31, | Year Ended December 31, | |||||||
2016(a) | 2016(b) | |||||||
Total operating revenues | $ | 8,556 | $ | 32,342 | ||||
Net income attributable to common shareholders | 577 | 1,562 | ||||||
Basic earnings per share | $ | 0.63 | $ | 1.69 | ||||
Diluted earnings per share | 0.62 | 1.69 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The purchase price equaled the estimated fair value of the net assets acquired and the liabilities assumed and, therefore, no goodwill or bargain purchase was recorded as of September 30, 2016. The purchase accounting is preliminary, and, although not expected, may be further adjusted from what is shown above. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition as more information is obtained about the fair value of assets acquired and liabilities assumed; however, Generation expects to finalize these amounts by the first quarter of 2017.
The fair values of ConEdison Solutions’ assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices.
It is impracticable to determine the post-close impact of ConEdison Solutions as the operations of ConEdison Solutions have been integrated into Generation’s operations and are therefore not distinguishable after the acquisition.
The amounts above include adjustments fornon-recurring costs directly related to the merger of $639 million and intercompany revenue of $170 million for the three months ended March 31, 2016. The amounts above include adjustments fornon-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for the year ended December 31, 2016. 5. Regulatory Matters (All Registrants) Except for the matters noted below, the disclosures set forth in Note 3 — Regulatory Matters of the Exelon Illinois Regulatory Matters Distribution Formula Rate (Exelon and ComEd). On April 13, On December 6, 2016, the ICC issued a final order approving the 2016 distribution formula rate, which included a total increase to the revenue requirement of $127 million, reflecting an increase of $134 million for the initial revenue requirement for 2016 and a decrease of $7 million related to the annual reconciliation for 2015. On December 20, 2016, the ICC granted ComEd’s and other parties’ joint application for rehearing on the impact that changing ComEd’s OSHA recordable rate for 2014 and 2015 Illinois Future Energy Jobs Act (Exelon, Generation, and ComEd). Background On December 7, 2016, FEJA was signed into law by the Governor of Illinois. FEJA is effective June 1, 2017, and includes, among other provisions, (1) a ZES providing compensation for certain nuclear-powered generating facilities, (2) an extension of and certain adjustments to ComEd’s electric distribution formula rate, (3) new cumulative persisting annual energy efficiency MWh savings goals for ComEd, (4) revisions to the Illinois RPS requirements, (5) provisions for adjustments to or termination of FEJA programs if the average impact on ComEd’s customer rates exceeds specified limits, (6) revisions to the existing net metering statute to (i) mandate net metering for community generation projects, and establish billing procedures for subscribers to those projects, (ii) provide immediately for netting at the energy-only rate for nonresidential customers, andProposed Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)(a) On August 8, 2016, Generation executed a series of agreements with Entergy Nuclear FitzPatrick LLC (Entergy) to acquire the 838MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York for a cash purchase price of $110 million. As part of the transaction, Generation would receive the FitzPatrick NDT fund assets and assume the obligation to decommission FitzPatrick. Closing of the transaction is currently anticipated to occur in the second quarter of 2017 and is dependent upon regulatory approval by FERC, NRC and the New York Public Service Commission (NYPSC). The transaction is also subject to the notification and reporting requirements of the HSR Act (which has been completed) and other customary closing conditions. The NRC license for FitzPatrick expires in 2034. Entergy had previously announced plans in November 2015 to early retire FitzPatrick at the end of the current fuel cycle in January 2017. Under the terms of the agreements, Generation will reimburse Entergy for approximately $200 million to $250 million of incremental costs to prepare for and conduct the plant refueling outage as well as to operate and maintain the plant after the refueling outage, scheduled to end in February 2017, through the closing date. These are costs which otherwise would have been avoided by FitzPatrick’s planned permanent shutdown in January 2017. Generation will be entitled to all revenues from FitzPatrick’s electricity and capacity sales for the period commencing upon completion of the refueling outage through the acquisition closing date. The agreements provide for certain termination rights, including the right of either party to terminate if the transaction has not been consummated within 12 months due to failure to obtain the required regulatory approvals.On October 11, 2016, Public Citizen, Inc. filed a protest with FERC challenging Generation and Entergy’s application to FERC for the transfer of ownership of FitzPatrick. No other party to the proceeding has filed any protests or comments. Generation and Entergy had requested FERC to approve the FitzPatrick transaction by November 18, 2016, however FERC is under no obligation to do so. The timing of FERC’s decision on Generation and Entergy’s application and the outcome of this protest are currently uncertain. Refer to Note 5 —Regulatory Matters for additional information on the New York CES and ZEC program.The transaction is expected to be accounted for as a business combination. For accounting and financial reporting purposes, the costs for which Generation reimburses Entergy as well as the revenue received from FitzPatrick prior to the closing of the transaction will be treated as part of the purchase price consideration. Generation will record the fair value of the assets acquired and liabilities assumed as of the acquisition date. To the extent the purchase price is greater than the fair value of the net assets acquired, goodwill will be recorded. To the extent the fair value of the net assets acquired is greater than the purchase price, a bargain purchase gain will be recorded.COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)(Dollars in millions, except per share data, unless otherwise noted)As of September 30, 2016, Generation has paid a non-refundable deposit of $10 million and reimbursed Entergy for $9 million in costs all of which have been classified with Other noncurrent assets on Exelon’s and Generation’s Consolidated Balance Sheets. These amounts are also reflected within Acquisition of businesses on Exelon’s and Generation’s Consolidated Statements of Cash Flows.Asset Divestitures (Exelon, Generation, PHI and Pepco)On April 21, 2016, Generation completed the sale of the retired New Boston generating site, located in Boston, Massachusetts, resulting in a pre-tax gain of approximately $32 million.On May 2, 2016, Pepco completed the sale of the New York Avenue land parcel, located in Washington, D.C., resulting in a pre-tax gain of approximately $8 million at Pepco. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain was recorded in the Exelon and PHI Consolidated Statements of Operations and Comprehensive Income.On June 16, 2016, Generation initiated the sales process of its Upstream business by executing a forbearance agreement with the lenders of the nonrecourse debt. See Note 10 — Debt and Credit Agreements for more information. As of September 30, 2016, $46 million of Property, plant and equipment and $5 million of Asset retirement obligation are classified as held for sale within Other current assets and Other current liabilities, respectively, on Exelon’s and Generation’s Consolidated Balance Sheets. In October 2016, Generation entered into an agreement to sell a portion of the Upstream assets which is expected to close before December 31, 2016.In July 2016, DPL completed the sale of a 9 acre land parcel located on South Madison Street in Wilmington, DE, resulting in a pre-tax gain of approximately $4 million. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain was recorded in the Exelon and PHI Consolidated Statements of Operations and Comprehensive Income.(b) 20152016 Form10-K and Note 7 — Regulatory Matters of the PHI 2015 Form 10-K appropriately represent, reflect, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.2016,2017, ComEd filed its annual distribution formula rate with the ICC pursuant to EIMA. The filing establishes the revenue requirement used to set the rates that will take effect in January 20172018 after the ICC’s review and approval, which is due by December 2016.2017. The revenue requirement requested is based on 20152016 actual costs plus projected 20162017 capital additions as well as an annual reconciliation of the revenue requirement in effect in 20152016 to the actual costs incurred that year. ComEd’s 20162017 filing request includes a total increase to the revenue requirement of $138$96 million, reflecting an increase of $139$78 million for the initial revenue requirement for 2017 and a decreasean increase of $1$18 million related to the annual reconciliation for 2015.2016. The revenue requirement for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.71%6.47% inclusive of an allowed ROE of 8.64%8.40%, reflecting the average rate on30-year treasury notes plus 580 basis points. The annual reconciliation for 20152016 provided for a weighted average debt and equity return on distribution rate base of 6.69%6.45% inclusive of an allowed ROE of 8.59%8.34%, reflecting the average rate on30-year treasury notes plus 580 basis points less a performance metrics penalty of 56 basis points. See table below for ComEd’s regulatory assets associated with its distribution formula rate. For additional information on ComEd’s distribution formula rate filings see Note 3 — Regulatory Matters of the Exelon 2016 Form10-K.Form 10-K.has on the revenue requirement approved in this order. On March 22, 2017, the ICC issued an order approving ComEd’s proposal to reduce the 2016 revenue requirement by $18 million, which will be reflected in customer rates in 2017.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(iii) transition from netting at the full retail rate to the energy-only rate for certain residential net metering customers once the net meter customer load equals 5% of total peak demand supplied in the previous year and (7) support for low income rooftop and community solar programs.
Zero Emission Standard
FEJA includes a ZES that provides compensation through the procurement of ZECs targeted at preserving the environmental attributes ofzero-emissions nuclear-powered generating facilities that meet specific eligibility criteria. ZES will have a10-year duration extending through May 31, 2027. Eligible generators may participate in a procurement event overseen by the IPA and selected generators will directly contract with Illinois utilities for the procurement of the ZECs based upon the number of MWh produced by the eligible facilities, subject to specified annual caps. The ZEC price will be based upon the current social cost of carbon as determined by the federal government and is initially established at $16.50 per MWh of production, subject to future adjustments based on specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices.
Illinois utilities, including ComEd, will be required to purchase from eligible nuclear facilities an amount of ZECs equivalent to 16% of the actual amount of electricity delivered in 2014. ComEd will recover all costs associated with purchasing ZECs through a new rate rider, which will provide for an annual reconciliation andtrue-up to actual costs incurred by ComEd to purchase ZECs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods.
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. One lawsuit was filed by customers of ComEd, led by the Village of Old Mill Creek, and the other was brought by the EPSA and three other electric suppliers. Both lawsuits argue that the Illinois ZEC program will distort FERC’s energy and capacity market auction system of setting wholesale prices, and seek a permanent injunction preventing the implementation of the program. Exelon intervened and filed motions to dismiss in both lawsuits. These motions are currently pending. In addition, on March 31, 2017, plaintiffs in both lawsuits filed motions for preliminary injunction with the court. Exelon cannot predict the outcome of these lawsuits. It is possible that resolution of these matters could have a material, unfavorable impact on Exelon’s and Generation’s results of operations, financial positions and cash flows.
See Note 7 — Early Nuclear Plant Retirements for the impacts of the provisions above on Generation’s Consolidated Balance Sheets and Consolidated Statements of Operations and Comprehensive Income. These provisions do not impact ComEd’s Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income or Consolidated Statements of Cash Flows until second quarter of 2017.
ComEd Electric Distribution Rates
FEJA extends the sunset date for ComEd’s performance-based electric distribution formula rate from 2019 to the end of 2022, allows ComEd to revise the electric distribution formula rate to eliminate the ROE collar, and allows ComEd to implement a decoupling tariff if the electric distribution formula rate is terminated at any time. ComEd will revise its electric distribution formula rate to eliminate the ROE collar beginning with the reconciliation filed in 2018 for the 2017 calendar year. Elimination of the ROE collar effectively offsets the favorable or unfavorable impacts to Operating revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer. ComEd began reflecting the impacts of this change in its electric distribution services costs regulatory asset beginning in first quarter 2017. As of March 31, 2017, ComEd recorded an increase to Operating revenues and its electric distribution services costs regulatory asset of approximately $16 million for this change.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
FEJA requires ComEd to makenon-recoverable contributions to low income energy assistance programs of $10 million per year for 5 years as long as the electric distribution formula rate remains in effect. With the exception of these contributions, ComEd will recover from customers, subject to certain caps explained below, the costs it incurs pursuant to FEJA either through its electric distribution formula rate or other recovery mechanisms.
Energy Efficiency
Existing Illinois law requires ComEd to implement cost-effective energy efficiency measures and, for a10-year period ending May 31, 2018, cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers.
Beginning January 1, 2018, FEJA provides for new cumulative annual energy efficiency MWh savings goals for ComEd, which are designed to achieve 21.5% of cumulative persisting annual MWh savings by 2030, as compared to the deemed baseline of 88 million MWhs of electric power and energy sales. FEJA, deems the cumulative persisting annual MWh savings to be 6.6% from 2012 through the end of 2017. ComEd expects to spend approximately $250 million to $400 million annually from 2017 through 2030 to achieve these energy efficiency MWh savings goals. In addition, FEJA extends the peak demand reduction requirement from 2018 to 2026. Because the new requirements apply beginning in 2018, FEJA extends the existing energy efficiency plans, which were due to end on May 31, 2017, through December 31, 2017. FEJA also exempts customers with demands over 10 MW from energy efficiency plans and requirements beginning June 1, 2017.
FEJA allows ComEd to cancel its existing energy efficiency rate rider and replace it with an energy efficiency formula rate, and to defer energy efficiency costs (except for any voltage optimization costs which will be recovered through the electric distribution formula rate) as a separate regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd will earn a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on ayear-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Through December 31, 2030, the return on equity that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd will be required to file an update to its energy efficiency formula rate on or before June 1 each year, with resulting rates effective in January of the following year. The annual update will be based on projected current year energy efficiency costs and the related projectedyear-end regulatory asset balance less any related deferred taxes. The update will also include a reconciliation of any differences between the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs andyear-end energy efficiency regulatory asset balances less any related deferred taxes.
ComEd expects to cancel its existing energy efficiency rider after FEJA becomes effective on June 1, 2017, at which time it must perform a reconciliation of revenues and costs incurred through the cancellation date and issue aone-time credit on retail customers’ bills for any over-recoveries. As of March 31, 2017, ComEd’s over-recoveries associated with its existing energy efficiency rider of $139 million were reflected in Current regulatory liabilities on Exelon’s and ComEd’s Consolidated Balance Sheets. ComEd expects to provide aone-time credit to customers in the second half of 2017 to address this over-recovery.
Renewable Portfolio Standard
Existing Illinois law requires ComEd to purchase each year an increasing percentage of renewable energy resources for the customers for which it supplies electricity. This obligation is satisfied through the procurement
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(Dollars in millions, except per share data, unless otherwise noted)
of RECs. FEJA revises the Illinois RPS to require ComEd to procure RECs for all retail customers by June 2019, regardless of the customers’ electricity supplier, and provides support forlow-income rooftop and community solar programs, which will be funded by the existing Renewable Energy Resources Fund and ongoing RPS collections. ComEd will recover all costs associated with purchasing RECs through rate riders, which will provide for a reconciliation andtrue-up to actual costs, with any difference between revenues and expenses to be credited to or collected from ComEd’s retail customers in subsequent periods. The first reconciliation andtrue-up for RECs will cover revenues and costs for the four year period beginning June 1, 2017 through May 31, 2021. Subsequently, the RPS rate rider will provide for an annual reconciliation andtrue-up.
Customer Rate Increase Limitations
FEJA includes provisions intended to limit the average impact on ComEd customer rates for recovery of costs incurred under FEJA as follows: (1) for a typical ComEd residential customer, the average impact must be less than $0.25 cents per month, (2) for nonresidential customers with a peak demand less than 10 MW, the average annual impact must be less than 1.3% of the average amount paid per kWh for electric service by Illinois commercial retail customers during 2015, and (3) for nonresidential customers with a peak demand greater than 10 MW, the average annual impact must be less than 1.3% of the average amount paid per kWh for electric service by Illinois industrial retail customers during 2015.
By June 30, 2017, ComEd must submit a10-year projection to the ICC of customer rate impacts for residential customers and nonresidential customers with a peak demand less than 10 MW. Thereafter, beginning in 2018, ComEd must submit a report to the ICC for residential customers and nonresidential customers with a peak demand less than 10 MW by February 15th and June 30th of each year, respectively. For nonresidential customers with a peak demand greater than 10 MW, ComEd must submit a report to the ICC by May 1 of each year if a rate reduction will be necessary in the following year. For residential customers, the reports will include the actual costs incurred under FEJA during the preceding year and a rolling10-year customer rate impact projection. The reports for nonresidential customers with a peak demand less than 10 MW will also include the actual costs incurred under FEJA during the preceding year, as well as the average annual rate increase from January 1, 2017 through the end of the preceding year and the average annual rate increase projected for the remainder of the10-year period.
If the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations during the first four years, ComEd is required to decrease costs associated with FEJA investments, including reductions to ZEC contract quantities. If the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations during the last six years, ComEd is required to demonstrate how it will reduce FEJA investments to ensure compliance. If the actual residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations for any one year, ComEd is required to submit a corrective action plan to decrease future year costs to reduce customer rates to ensure future compliance. If the actual residential customer or nonresidential customer rate exceeds the limitations for two consecutive years, ComEd can offer to credit customers for amounts billed in excess of the limitations or ComEd can terminate FEJA investments. If ComEd chooses to terminate FEJA investments, the ICC shall order termination of ZEC contracts and further initiate proceedings to reduce energy efficiency savings goals and terminate support forlow-income rooftop and community solar programs. ComEd is allowed to fully recover all costs incurred as of and up to the date of the programs’ termination.
For the energy efficiency formula, ComEd will record a regulatory asset or liability and corresponding increase or decrease to Operating revenues for any differences between the revenue requirement in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s
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(Dollars in millions, except per share data, unless otherwise noted)
reconciliation. For the other rate riders to be established under FEJA, ComEd will record a regulatory asset or liability for any differences between revenues and incurred expenses.
Other than recognizing the impacts of eliminating the ROE collar in its electric distribution formula rate, FEJA did not have any impacts on ComEd’s Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income or Consolidated Statements of Cash Flows in first quarter 2017.
Energy Efficiency and Renewable Energy Resources (Exelon and ComEd). In accordance with legislation in effect on December 31, 2016, the IPA’s Procurement Plans include the procurement of cost-effective renewable energy resources in amounts that equal or exceed a minimum target percentage of the total electricity that each electric utility supplies to its eligible retail customers. The June 1, 2016 target renewable energy resources obligation for the utilities was at least 11.5%. This obligation increases by at least 1.5% each year thereafter to an ultimate target of at least 25% by June 1, 2025. All goals are subject to rate impact criteria set forth by Illinois legislation. As of March 31, 2017, ComEd had purchased renewable energy resources or equivalents, such as RECs, in accordance with the IPA Procurement Plan. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover procurement costs of RECs from retail customers withoutmark-up through rates.
In accordance with FEJA that takes effect on June 1, 2017, beginning with the plan or plans to be implemented in the 2017 delivery year, the IPA shall develop a long term renewable resources procurement plan (LT Plan). The RPS target percentages for the overall service territory have not changed through June 1, 2025 although FEJA extended the 25% RPS target to delivery years after 2025. Currently, each RES and each utility is responsible for the renewable resource obligation of the customers it supplies power for. Over time, this will change and the utility will procure renewable resources based on the retail load of substantially all customers in its service territory. For the delivery year beginning June 1, 2017, the LT Plan shall include cost effective renewable energy resources procured by the utility for the retail load the utility supplies and for 50% of the retail customer load supplied by Retail Electric Suppliers in the utility service territory on February 28, 2017. Utility procurement for RES supplied retail customer load will increase to 75% June 1, 2018 and to 100% beginning June 1, 2019.
Grand Prairie Gateway Transmission Line (Exelon and ComEd). On December 2, 2013, ComEd filed a request to obtain the ICC’s approval to construct a60-mile overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois. On October 22, 2014, the ICC issued an Order approving ComEd’s request. The City of Elgin and certain other parties each filed an appeal of the ICC Order in the Illinois Appellate Court for the Second District. ComEd then reached a settlement of the appeal filed by all parties except Elgin. On March 31, 2016, the Illinois Appellate Court issued its opinion affirming the ICC’s grant of a certificate to ComEd to construct and operate the line. Elgin did not seek further review of the Illinois Appellate Court decision. On May 28, 2014, in a separate proceeding, FERC issued an order granting ComEd’s request to include 100% of the capital costs recorded to construction work in progress during construction of the line in ComEd’s transmission rate base. If the project is cancelled or abandoned for reasons beyond ComEd’s control, FERC approved the ability for ComEd to recover 100% of its prudent costs incurred after May 21, 2014 and 50% of its costs incurred prior to May 21, 2014 in ComEd’s transmission rate base. The costs incurred for the project prior to May 21, 2014 were immaterial. ComEd has acquired the necessary land rights across the project route through voluntary transactions. ComEd began construction of the line during 2015 with an expected and placed the linein-service date of on April 7, 2017.
FutureGen Industrial Alliance, Inc (Exelon and ComEd).During 2013, the ICC approved, and directed ComEd and Ameren (the Utilities) to enter into 20-year sourcing agreements with FutureGen Industrial Alliance, Inc (FutureGen), under which FutureGen will retrofit and repower an existing plant in Morgan County, Illinois to a 166 MW near zero emissions coal-fueled generation plant, with an assumed commercial operation date in 2017. The order also directs ComEd and Ameren to recover these costs from their electric distribution customers through the use of a tariff, regardless of whether they purchase electricity from ComEd or Ameren, or from competitive electric generation suppliers.
In February 2013, ComEd filed an appeal with the Illinois Appellate Court questioning the legality of requiring ComEd to procure power for retail customers purchasing electricity from competitive electric generation suppliers. On July 22, 2014, the Illinois Appellate Court issued its ruling re-affirming the ICC’s order requiring ComEd to enter into the sourcing agreement with FutureGen and allowing the use of a tariff to recover its costs. ComEd decided not to appeal the Illinois Appellate Court’s decision to the Illinois Supreme Court. However, the competitive electric generation suppliers and several large consumers petitioned for leave to appeal the Illinois Appellate Court’s decision. On November 26, 2014, the Illinois Supreme Court granted the petition. ComEd executed the sourcing agreement with FutureGen in accordance with the ICC’s order. In addition, ComEd filed a petition with the ICC seeking approval of the tariff allowing for the recovery of its costs associated with the FutureGen contract from all of its electric distribution customers, which was approved by the ICC on September 30, 2014.
In February 2015, the DOE suspended funding for the cost development of FutureGen. On January 13, 2016, FutureGen informed the Illinois Supreme Court that it had ceased all development efforts on the FutureGen project. Accordingly, FutureGen requested that the court dismiss the proceeding as moot. In February 2016, FutureGen terminated its sourcing agreement with ComEd. On May 19, 2016, the Illinois Supreme Court dismissed the matter as moot. As a result, ComEd is under no further obligation under this agreement.
Pennsylvania Regulatory Matters
Pennsylvania Procurement Proceedings (Exelon and PECO). Through PECO’s first two PAPUC approved DSP Programs, PECO procuredprocures electric supply for its default electric customers through PAPUC approved competitive procurements.
On March 17, 2016, PECO filed its fourth DSP I and DSP II expired onProgram with the PAPUC proposing a24-month term from June 1, 2017 through May 31, 2013 and May 31, 2015, respectively.
The second2019, in compliance with electric generation procurement guidelines set forth in Act 129. On December 8, 2016, the PAPUC approved the fourth DSP Program included a number of retail market enhancements recommended byfor the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. PECO was also directed to submit a plan tomodified48-month term
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and deferred CAP Shopping to another proceeding. OCA and Low Income Advocates subsequently filed a Petition for Reconsideration and Clarification related to CAP Shopping. On March 16, 2017 the PAPUC granted reconsideration and consolidated the proceeding with the DSP II docket, which includes the pending CAP Shopping plan that would allow its low-income CAP customers to purchase their generation supply from EGSs beginning in April 2014. In May 2013, PECO filed its CAP Shopping Plan withEGSs. PAPUC referred the PAPUC. By an Order entered on January 24, 2014, the PAPUC approved PECO’s plan, with modifications,consolidated proceedings to make CAP shopping available beginning April 15, 2014. On March 20, 2014, the Office of Consumer Advocate (OCA) and low-income advocacy groups filed an appeal and emergency request for a stay with the Pennsylvania Commonwealth Court (Court), claiming that the PAPUC-ordered CAP Shopping plan does not contain sufficient protections for low-income customers. On July 14, 2015, the Court issued opinions on the OCA and low-income advocacy group appeal. Specifically, the Court remanded the issue to the PAPUC with instructions that it approve a rule revision to the PECO CAP Shopping Plan that would prohibit CAP customers from entering into contracts with an EGS that would impose early cancellation/termination fees. The PAPUC, as well as the low-income advocates and the Office of Consumer Advocate, appealed the Court’s decision. On April 5, 2016, the Pennsylvania Supreme Court declined to accept the appeals. On May 11, 2016, the PAPUC issued a Secretarial Letter requiring PECO to propose a rule revision to the PECO CAP Shopping Plan consistent with the Court’s decision. On July 19, 2016, PECO filed a letter stating its intent to revise its Plan by September 1, 2016 to incorporate the rule revision. On September 1, 2016, PECO filed its proposed rule revision that is consistent with the Court’s opinion with a proposed effective date of April 14, 2017.
On December 4, 2014, the PAPUC approved PECO’s third DSP Program. The program has a 24-month term from June 1, 2015 through May 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. Under the program, PECO procured electric supply through four competitive procurements for fixed price full requirements contracts of two years or less for the residential classes and small and medium commercial classes and spot market price full requirement contracts for the large commercial and industrial class load. Beginning in June 2016, the medium commercial class (101-500 kW) moved to spot market pricing. In September 2016, PECO entered into contracts with PAPUC-approved bidders, including Generation, resulting from the final of its four scheduled procurements. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO’s Consolidated Statement of Operations and Comprehensive Income.
On March 17, 2016, PECO filed its fourth DSP Program with the PAPUC proposing a 24-month term from June 1, 2017 through May 31, 2019, in compliance with electric generation procurement guidelines set forth in Act 129. On October 4, 2016, the Administrative Law Judge recommended that PECO’s previously filed partial settlement be approved without modification. The settlement would extend the program period through May 2021for hearing and consolidate the Medium Commercial and Large Commercial classes of default service customers into a Consolidated Large Commercial Class proposed by the Company. The issue of PECO’s implementation of CAP Shopping was reserved for briefing, and the Administrative Law Judge determined that issue was not a part of the DSP IV case. A decision by the PAPUC is expected in December 2016.
For further information on the Pennsylvania procurement proceedings, see Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K.decision.
Energy Efficiency ProgramsPennsylvania Act 11 of 2012 (Exelon and PECO).On June 19, 2015, In February 2012, Act 11 was signed into law, which provided the PAPUC issued its Phase III EE&Cauthority to approve the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities’ aging electric and natural gas distribution systems in Pennsylvania. Prior to recovering costs pursuant to a DSIC, the PAPUC’s implementation order that provides energy consumption reduction requirementsrequires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) approved by the Commission, which outlines how the utility is planning to increase its investment for the third phase of Act 129’s EE&C program with a five-year term from June 1, 2016 through May 31, 2021.
Pursuant to the Phase III implementation order, PECO filed its five-year EE&C Phase III Plan with the PAPUC on November 30, 2015. The Plan sets forth how PECO will reduce electric consumption by at least 1,962,659 MWh, with a goal of 2,100,875 MWh in its service territory for the period June 1, 2016 through May 31, 2021.repairing, improving or replacing aging infrastructure. The PAPUC approved PECO’s EE&C Phase III Plan,petition for its proposed electric DSIC and LTIIP on October 22, 2015 for spending of $275 million over a 5 year period through 2020. On March 1, 2017, PECO filed a petition with requested clarifications, on May 19, 2016.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)the PAPUC for approval of a Modified Gas LTIIP to increase expenditures to $762 million from the approved $534 million over the 10 year LTIIP period through 2022.
(Dollars in millions, except per share data, unless otherwise noted)
For further information on energy efficiency programs, see Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K.
Maryland Regulatory Matters
20162017 Maryland Electric Distribution Rate CaseRates (Exelon, PHI and Pepco).On April 19, 2016,March 24, 2017, Pepco filed an application with the MDPSC requesting an increase of $127 million to its electric distribution base rates, which was later updated to $103$69 million based on a requested ROE of 10.6%10.1%. The application is inclusive ofincludes a request seeking recoveryfor an income tax adjustment to reflect full normalization of Pepco’s regulatory assetsremoval costs associated with its AMI program over a five-year period supported by evidence demonstrating that the benefitspre-1981 property, which accounts for $18 million of the AMI program exceedrequested increase. Pepco expects a decision in the costs on a present value basis. Any adjustments to rates approved bymatter in the MDPSC are expected to take effect in November 2016. In addition to the proposed rate increase, Pepco is proposing to continue its Grid Resiliency Program initially approved in July 2013 in connection with Pepco’s electric distribution rate case filed in November 2012. Under the Grid Resiliency Program, Pepco is authorized to receive recoveryfourth quarter of specific investments as the assets are placed in service through the Grid Resiliency Charge. In connection with the Grid Resiliency Program, Pepco proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse technology by investing $16 million a year for two years for a total of $32 million. Pepco2017, but cannot predict how much of the requested rate increase the MDPSC will approve or if it will approve a continuation of Pepco’s Grid Resiliency Program proposal.the requested income tax adjustment.
2016 Maryland Electric Distribution Base Rates (Exelon, PHI and DPL). On July 20, 2016, DPL filed an application withFebruary 15, 2017, the MDPSC requestingapproved an increase of $66 million to itsin DPL electric distribution base rates which was later updated to $57of $38 million based on a requested ROE of 10.6%9.6%. The application is inclusive of anew rates became effective for services rendered on or after February 15, 2017. The MDPSC also denied DPL’s request seeking recovery of DPL’s regulatory assets associated with its AMI program over a five-year period supported by evidence demonstrating that the benefits of the AMI program exceed the costs on a present value basis. Any adjustments to rates approved by the MDPSC are expected to take effect in February 2017. DPL cannot predict how much of the requested increase the MDPSC will approve. In addition to the proposed rate increase, DPL is proposing to continue its Grid Resiliency Program, initially approved in September 2013 in connection with DPL’s electric distribution rate case filed in February 2013. Under the Grid Resiliency Program,through which DPL is authorizedproposed to receive recovery of specific investments as the assets are placed in service through the Grid Resiliency Charge. In connection with the Grid Resiliency Program, DPL proposesinvest $4.6 million a year for two years to accelerate improvement toimprove priority feeders and install single-phase reclosing fuse technology by investing $4.6 million a year for two years for a totaltechnology. The final order did not result in the recognition of $9.2 million. DPL cannot predict whetherany incremental regulatory assets or liabilities during the MDPSC will approve a continuationfirst quarter of DPL’s Grid Resiliency Program proposal.2017.
2015 Maryland Electric and Natural Gas Distribution Rate CaseCash Working Capital Order (Exelon and BGE). On November 6, 2015,17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its Provider of Last Resort service, also known as Standard Offer Service (SOS), as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover all of itsSOS-related costs. The Administrative Charge is now comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which is an adder to the utility’s SOS rate to act as amended througha proxy for retail suppliers’ costs. The Commission accepted BGE positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a modest return on the courseSOS. The Commission ruled that the level of the proceeding,administrative adjustment will be determined in BGE’s next rate case. On December 16, 2016, MDPSC Staff requested clarification concerning the amount of return on the SOS awarded to BGE filed for electric and natural gas base rate increases withon December 19, 2016, the MDPSC, ultimately requesting annual increasesresidential consumer advocate sought rehearing of $116 million and $78 million respectively, of which $104 million and $37 million, were related to recovery of electric and natural gas smart grid initiative costs, respectively. BGE also proposed to recover an annual increase of approximately $30 million for Baltimore City underground conduit fees through a surcharge.
the return awarded. On June 3, 2016,January 24, 2017, the MDPSC issued an order in whichdenying the MDPSC found compelling evidence to conclude that BGE’s smart grid initiative overall was cost beneficial to customers. However,Staff request for clarification and the June 3 order contained several cost disallowances and adjustments, including not allowing BGE to defer or recover through a surchargeresidential consumer advocate request for rehearing. On February 22, 2017, the $30 million increase in annual Baltimore City underground conduit fees. On June 30, 2016, BGEresidential consumer advocate filed a petition for rehearingan appeal of the June 3 order requesting that the MDPSC modify its order to reverse certain decisions including the decision associatedMDPSC’s orders with the Circuit Court for Baltimore City underground conduit fees. OPC also subsequently filed for a petition for rehearingCity. BGE cannot predict the outcome of the June 3 order.this appeal.
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(Dollars in millions, except per share data, unless otherwise noted)
On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustments related to the smart grid initiative. Through the combination of the orders, the MDPSC authorized electric and natural gas rate increases of $44 million and $48 million, respectively, and an allowed ROE for the electric and natural gas distribution businesses of 9.75% and 9.65%, respectively. The new electric and natural gas base rates took effect for service rendered on or after June 4, 2016. However, MDPSC’s July 29 order on the petition on rehearing still did not allow BGE to defer or recover through a surcharge the increase in Baltimore City underground conduit fees.
On August 26, 2016, BGE filed an appeal of the MDPSC’s orders with the Circuit Court for Baltimore County. On August 29, 2016, the residential consumer advocate also filed an appeal of the MDPSC’s order but with the Circuit Court for Baltimore City. BGE cannot predict the outcomes of these appeals. Refer to the Smart Meter and Smart Grid Investment disclosure below for further details on the impact of the ultimate disallowances contained in the orders to BGE.
Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and natural gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of September 30, 2016March 31, 2017 and December 31, 2015,2016, the balance of BGE’s regulatory asset was $235$225 million and $196$230 million, respectively, representing incremental program deployment costs. The current quarter balance of $235$225 million consists of three major components, including $148$140 million of unamortized incremental deployment costs of the AMI program, $55$53 million of unamortized costs of thenon-AMI meters replaced under the program, and $32 million related to post-test year incremental program deployment costs incurred prior to approval became effective June 2016. The balance as of September 30, 2016March 31, 2017 reflects the impact of the cost disallowances and adjustments discussed below. The incremental deployment costs for the AMI program and thenon-AMI meter components of the regulatory asset are being recovered through rates and amortized to expense over a 10 year period, while the post-test year incremental program deployment costs have not yet been approved for recovery by the MDPSC. A return on the regulatory asset is currently included in rates, except for the $55$53 million portion representing the unamortized cost of the retirednon-AMI meters and a $32 million portion related to post-test year incremental program deployment costs.
As parta combined result of the MDPSC orders in BGE’s 2015 electric and natural gas distribution rate case, filed on November 6, 2015, BGE sought recovery of its smart grid initiative costs, supported by evidence demonstrating that BGE had, in fact, implemented a cost-beneficial advanced metering system. On June 3, 2016, the MDPSC issued an order concluding that the smart grid initiative overall is cost beneficial to its customers. However, the June 3 order contained several cost disallowances and adjustments including disallowances of certain program and meter installation costs and denial of recovery of any return on unrecovered costs for non-AMI meters replaced under the program. On June 30, 2016, BGE filed a petition for rehearing of the June 3 order requesting that the MDPSC modify its order to reverse certain decisions and change certain of the cost disallowances and adjustments to enable BGE to defer those costs for recovery through future electric and natural gas rates. OPC also subsequently filed for a petition for rehearing of the June 3 order. On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustments related to the smart grid initiative. On August 26, 2016, BGE filed an appeal of the MDPSC’s orders with the Circuit Court for Baltimore County. On August 29, 2016, the residential consumer advocate also filed an appeal of the MDPSC’s order but with the Circuit Court for Baltimore City. BGE cannot predict the outcomes of these appeals.
As a combined result of the MDPSC orders, BGE recorded a $52 million charge in June 2016 to Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income
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(Dollars in millions, except per share data, unless otherwise noted)
reducing certain regulatory assets and other long-lived assets. Pursuant to the combined MDPSC orders, BGE alsoassets and reclassified $55$56 million ofnon-AMI plant costs from Property, plant and equipment, net to Regulatory assets on Exelon’s and BGE’s Consolidated Balance Sheets as of September 30, 2016.Sheets. For further information, see Note 3 — Regulatory—Regulatory Matters of the Exelon 20152016 Form10-K.
2013 Maryland Electric and Natural Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, and as amended on August 23, 2013, BGE filed for electric and natural gas base increases with the MDPSC. In addition to these requested rate increases, BGE’s application also included a request for recovery of incremental capital expenditures and operating costs associated with BGE’s proposed short-term reliability improvement plan (the ERI initiative) in response to a MDPSC order through a surcharge separate from base rates.
On December 13, 2013, the MDPSC issued an order authorizing BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements premised upon the condition that the MDPSC approve specific projects in advance of cost recovery. As of September 30, 2016, BGE has received approval of its updated surcharge filings three times for rates to be effective in 2014, 2015 and 2016.
In January 2014, the residential consumer advocate in Maryland filed an appeal to the order issued by the MDPSC on December 13, 2013 in BGE’s 2013 electric and natural gas distribution rate cases. The residential consumer advocate filed its related legal memorandum on August 22, 2014, challenging the MDPSC’s approval of the ERI initiative surcharge. BGE submitted a response to the appeal on October 15, 2014, and a hearing was held on November 17, 2014. On October 26, 2015, the Circuit Court for Baltimore City issued an order affirming the MDPSC decision. However, on November 23, 2015, the residential consumer advocate filed an appeal of the Circuit Court’s decision with the Maryland Court of Special Appeals. On March 7, 2016, the consumer advocate withdrew its appeal and no further action is expected.
MDPSC New Generation Contract Requirement (Exelon, Generation, BGE, PHI, Pepco and DPL).On April 12, 2012, the MDPSC issued an order that requires BGE, Pepco and DPL (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 MWs beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, the winning bidder was to construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015, and each of the Contract EDCs was to recover its costs associated with the contract through surcharges on its respective SOS customers.
In response to a complaint filed by a group of generating companies in the PJM region, on September 30, 2013, the U.S. District Court for the District of Maryland issued a ruling that the MDPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, on October 1, 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City upheld the MDPSC’s orders requiring the Contract EDCs to enter into the contracts.
On October 24, 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. In November 2013 both the winning bidder and the MDPSC appealed the Federal district court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the lower Federal court ruling. On November 26, 2014, both the winning bidder and the MDPSC petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision. On October 19, 2015, the U.S. Supreme Court agreed to review the decision. On April 19, 2016, the U.S. Supreme Court unanimously affirmed the Fourth Circuit’s ruling upholding the Federal district court’s decision.
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(Dollars in millions, except per share data, unless otherwise noted)
The decision of the Maryland Circuit Court was appealed to the Maryland Court of Special Appeals and was stayed pending decision by the U.S. Supreme Court. On August 1, 2016, the Contract EDCs submitted a filing requesting that the MDPSC take notice of the U.S. Supreme Court’s decision, and notifying the MDPSC that the Contract EDCs will dismiss their appeal pending at the Maryland Court of Special Appeals. On September 14, 2016, the Maryland Court of Special Appeals dismissed the pending appeal and the matter is considered closed.
Delaware Regulatory Matters
Gas Cost Rates (Exelon, PHI and DPL).DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2016, DPL made its 2016-2017 GCR filing. The rates proposed in the 2016-2017 GCR filing resulted in a GCR increase of approximately 14%. On September 20, 2016, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2016, subject to refund and pending final DPSC approval. A settlement agreement was reached by all parties. On April 20, 2017, the DPSC issued an order which approved the settlement agreement and made the rates approved as final effective November 1, 2016.
2016 Electric and Natural Gas Distribution Base Rates (Exelon, PHI and DPL). On May 17, 2016, DPL filed an application with the DPSC to increase its annual electric and natural gas distribution base rates by $63 million (which was updated to $60 million on March 8, 2017) and $22 million, respectively, based on a requested ROE of 10.6%. While the DPSC is not required to issue a decision on the application within a specified period of time, Delaware law allowed DPL to put into effect $2.5 million of each of the rate increaseincreases two months after filing the applications which were effective July 16, 2016. It also allowsOn December 17, 2016, the entire requested rate increase seven months after filing,DPSC approved that an additional $30 million in electric distribution rates be implemented effective December 17, 2016, subject to a cap and a refund obligation based on the final DPSC order, and an additional $10 million in natural gas distribution rates be implemented effective December 17, 2016, subject to refund based on the final DPSC order.
On March 8, 2017, DPL cannot predict how muchentered into a settlement agreement with the Division of the requested increasePublic Advocate, Delaware Electric Users Group and the DPSC Staff in its electric distribution rate proceeding, which provides for an increase in DPL electric distribution rates of $31.5 million based on an ROE of 9.7%. The settlement agreement also provides that the rates currently in effect, as approved by the DPSC, effective July 16, 2016 and
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(Dollars in millions, except per share data, unless otherwise noted)
December 17, 2016 (as discussed above), will approve.remain in effect until the date of the final DPSC order and that no refund will be required. As a result, during the first quarter of 2017, DPL established a regulatory asset of $8 million for costs incurred to achieve the merger and reversed a regulatory liability of $1 million for electric revenues that are no longer subject to refund which resulted in an increase in net income of $5 million. DPL currently expects a final order on the settlement agreement during the second quarter of 2017.
On April 6, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate and the DPSC Staff in its natural gas distribution rate proceeding, which provides for an increase in DPL natural gas distribution rates of $4.9 million based on an ROE of 9.7%. The settlement agreement also provides that DPL will refund amounts in excess of the $4.9 million increase collected under the temporary rates effective July 16, 2016 and December 17, 2016 (as discussed above), and that the new rates will be effective within thirty days of DPSC approval of the settlement agreement. In the event that the final order reflects the settlement agreement, DPL does not expect the impact to be material to its financial statements. DPL currently expects a final order on the settlement agreement during the second quarter of 2017.
District of Columbia Regulatory Matters
2016 Electric Distribution Base Rates (Exelon, PHI and Pepco). On June 30, 2016, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by $86 million, which was updated to $82 million on October 14, 2016, and further updated to approximately $77 million on February 1, 2017, based on a requested ROE of 10.6%. The DCPSC has issued a procedural schedule indicating a final decision will be issued by July 25, 2017. Any adjustments to its rates approved by the DCPSC are expected to take effect soon thereafter. Pepco cannot predict how much of the requested increase the DCPSC will approve.
On April 18, 2016, a party to a separate DCPSC proceeding filed a motion to suspend Pepco’s bill stabilization adjustment (BSA), which decouples distribution revenues from utility customers from the amount of electricity delivered. On September 9, 2016, the DCPSC denied the party’s motion and determined that the appropriate forum in which to determine whether the BSA continues to be just and reasonable is in Pepco’s rate case proceeding. In addition, the DCPSC stated that it was putting Pepco on notice that all funds collected for the BSA from January 2015 to the issuance of a decision in the rate case proceeding are subject to refund should the DCPSC determine that such funds were not justly or reasonably collected. On November 22, 2016, following Pepco’s October 7, 2016 Pepco filedrequest for reconsideration of thisthe order, and requested clarificationthe DCPSC issued an order stating that theits September 9, 2016 order was not final and confirming that issues related to the BSA, matterincluding potential remedial actions, would be decidedaddressed in the basePepco’s rate case. Pepco also argued that, if the order were considered final, the DCPSC reconsider its ruling that funds collected from the BSA can be retroactively refunded. Pepco cannot predict the outcome of this matter or the impact of a refund if ordered by the DCPSC.
District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco). In May 2014, the Council of the District of Columbia enacted theThe Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provided was the enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative, which woulda $1 billion project to selectively place underground some of the District of Columbia’s most outage-prone power lines.
The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a volumetric surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financedfunded by the District of Columbia’sColumbia through the issuance of securitized bonds, which bonds will be repaid through a volumetric surcharge (the DDOT surcharge) on the electric bills of Pepco District of Columbia customers that Pepco will remit to the District of Columbia; and (iii) the remaining costs up to $125 million are to be coveredfunded by
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(Dollars in millions, except per share data, unless otherwise noted)
the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or
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(Dollars in millions, except per share data, unless otherwise noted)
assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.
In June 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia. In August 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds. In March 2016, the DCPSC’s orders approving the Triennial Plan and the application for financing were upheld upon the resolution of appeals that had been filed with the District of Columbia Court of Appeals. In compliance with the Improvement Financing Act, on September 30, 2016, Pepco and DDOT filed a Second Triennial Plan. Recognizing the delays to the First Triennial Plan, Pepco and DDOT requested that the DCPSC hold the Second Triennial Plan in abeyance.
In June 2015, an agency of the federal government served by Pepco asserted that the DDOT surcharge constitutes a tax on end users from which the federal government is immune. PHI
In March 2017, the Electric Company Infrastructure Improvement Financing Amendment Act of 2017 was introduced to the Council of the District of Columbia. The proposed amendment changes a portion of the funding structure for the DC PLUG initiative from securitized bonds issued by the District to apay-as-you-go structure with the cost imposed on the electric company and recovered by the electric company through a rate rider. This amendment would reduce the overall project authorization from $1 billion to $500 million and would provide that: (i) Pepco is currently evaluatingto fund approximately $250 million of the assertion andestimated cost to complete the resolutionDC PLUG initiative, recovering those costs through a volumetric surcharge on the electric bills of this matter will likely further delay implementationPepco District of Columbia customers; (ii) $188 million of the DC PLUG initiative.initiative cost would be funded through a charge collected from Pepco by the District of Columbia and Pepco would recover this charge from customers through a volumetric distribution rider; and; (iii) the remaining costs up to $62 million are to be covered by the existing capital projects program of DDOT. Pepco will not earn a return on or a return of the cost of the assets funded by the charge collected from Pepco by the District of Columbia or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount upon completion.
PHI believes that the proposed amendment addresses the assertion made by an agency of the federal government that the surcharge proposed in the Improvement Financing Act constitutes a tax on end users.
New Jersey Regulatory Matters
20162017 Electric Distribution Base Rates (Exelon, PHI and ACE). On March 30, 2017, ACE submitted an application with the NJBPU to increase its electric distribution rates by approximately $70 million (before New Jersey sales and use tax), based upon a requested ROE of 10.1%. The application also requests approval of a rate surcharge mechanism called the “System Renewal Recovery Charge,” which would permit more timely recovery of certain costs associated with reliability and system renewal-related capital investments. ACE currently expects a decision in this matter in the first quarter of 2018, but cannot predict if the NJBPU will approve the application as filed.
2016 Electric Distribution Rates (Exelon, PHI and ACE).On August 24, 2016, the NJBPU issued an order approving a stipulation of settlement among ACE, the New Jersey Division of Rate Counsel, NJBPU Staff and Unimin Corporation, and an increase of $45 million (before New Jersey sales and use tax) to its electric distribution base rates, with the new rates effective immediately. The stipulation of settlementwhich, among other things, provided that a determination on ACE’s grid resiliency program, PowerAhead, would be separated into a phase II of the rate proceeding and decided at a later date and the parties would seek to resolve the matter by the end of 2016, although resolution will most likely occur in the first quarter of 2017. PowerAhead includes capital investments to advance modernization of the electric grid through energy efficiency, increased distributed generation, and resiliency, focused on improving the distribution system’s ability to withstand major storm events. ACE currently expects this matter to conclude in the second quarter of 2017, but cannot predict if the NJBPU will approve the PowerAhead initiative.
Update and Reconciliation of Certain Under-Recovered Balances (Exelon, PHI and ACE).OnOn February 1, 2016,2017, ACE submitted its 20162017 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGsnon-utility generators and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollectible accounts.
The net impact of adjusting the charges as proposed is an
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(Dollars in millions, except per share data, unless otherwise noted)
overall annual rate increasedecrease of $9approximately $29 million (revised to $19approximately $32 million in April 2016,2017, based upon an update for actuals through March 2016)2017), including New Jersey sales and use tax. The matter is pending at the NJBPU. ACE has requested that the NJBPU place the new rates into effect by June 1, 2017. There is no assurance that NJBPU will put final rates in effect by the requested date.
New York Regulatory Matters
New York Clean Energy Standard (Exelon, Generation). On August 1, 2016, the New York Public Service Commission (NYPSC) issued an order establishing the Clean Energy Standard (CES),CES, a component of which includes creation of ais the Tier 3 Zero Emission Credit (ZEC)ZEC program targeted at preserving the environmental attributes ofzero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC. The New York State Energy Research and Development Authority (NYSERDA) will centrally procure the ZECs from eligible plants through a12-year contract, to be administered in sixtwo-year tranches, extending from April 1, 2017 through March 31, 2029. ZEC payments will be made to the eligible resources based upon the number of MWh produced, subject to
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(Dollars in millions, except per share data, unless otherwise noted)
specified caps and minimum performance requirements. The price to be paid for the ZECs under each tranche will be administratively determined using a formula based on the social cost of carbon as determined in 2016 by the federal government.government, subject to pricing adjustments designed to lower the ZEC price based on increase in underlying energy and capacity prices. The ZEC price for the first tranche has been set at $17.48 per MWh of production. Following the first tranche, the price will be updatedbi-annually. Each Load Serving Entity (LSE) shall be required to purchase an amount of ZECs equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers shall be incorporated into the commodity charges on customer bills.
The CESNYPSC initially identifies theidentified three plants eligible for the ZEC program to include, for now,program: the FitzPatrick, Ginna, and Nine Mile Point nuclear facilities. The program specifically provides that Nine Mile Point Units 1 & 2 qualify jointly as a single facility and if either unit permanently ceases operations then both units will no longer qualify for ZEC payments for the remainder of the program. As issued, the order providesalso provided that the duration of the program beyond the first tranche iswas conditional upon a buyer purchasing the FitzPatrick facility and taking title prior to September 1, 2018; however, Generation2018. On November 18, 2016, the required contracts with NYSERDA were executed for Ginna and CENG requested clarification, orNine Mile Point, in addition to Entergy’s execution of the alternative limited rehearing, that this condition is applicable torequired contract for the FitzPatrick facility only and has no bearingfacility. On March 31, 2017, Generation closed on the 12-year durationacquisition of the program for Ginna or Nine Mile Point. To date, severalFitzPatrick.
Several parties have filed with the NYPSC requests for rehearing or reconsideration of the CESCES. Generation and CENG also filed a request for clarification, or in the alternative limited rehearing, that the condition limiting the duration of the program beyond the first tranche be limited to the eligibility of the FitzPatrick plant only and have no bearing on Ginna or Nine Mile Point’s eligibility for the full12-year duration. On December 15, 2016, the NYPSC approved Generation’s and CENG’s petition to clarify this condition and denied all petitions for rehearing of the CES. Parties have untilmid-April to appeal to New York State court the denials of the requests for rehearing. In addition, a Petition seeking to invalidate the ZEC program was filed in New York State court by certain environmental groups and other parties on November 30, 2016, and amended on January 13, 2017, arguing that the NYPSC violated certain technical provisions of the State Administrative Procedures Act (SAPA) when adopting the ZEC program. On February 15, 2017, Generation and CENG filed a motion to dismiss the state court action. The NYPSC also filed a motion to dismiss the state court action. On March 24, 2017, the plaintiffs filed a memorandum of law opposing the motions to dismiss, and Generation and CENG filed a reply brief on April 28, 2017. The motion is pending.
On October 19, 2016, a coalition of fossil generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors. On December 9, 2016, Generation and CENG will seekfiled a motion to intervene in the case and to dismiss the lawsuit. The motion to intervene has been granted and the motion to dismiss is pending.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Other legal challenges remain possible, and the outcomes of each of these challenges are currentlywhich remain uncertain. Negotiations with NYSERDA regarding contracts for the sale of ZECs from Ginna, Nine Mile Point and FitzPatrick are ongoing, and Generation expects that NYSERDA will enter into final agreements during the fourth quarter of 2016. See Note 7 — Early Nuclear Plant Retirements for additional information relative to Ginna and Nine Mile Point. See Note 4 — Mergers,—Mergers, Acquisitions and Dispositions for additional information on Generation’s proposed acquisition of FitzPatrick.
Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation). In November 2014, in response to a petition filed by Ginna Nuclear Power Plant (Ginna) regarding the possible retirement of Ginna, the NYPSC directed Ginna and Rochester Gas & Electric Company (RG&E) to negotiate a Reliability Support Services Agreement (RSSA) to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time. During 2015 and 2016, Ginna and RG&E made filings with the NYPSC and FERC for their approval of the proposed RSSA. Although the RSSA was still subject to regulatory approvals, on April 1, 2015, Ginna began delivering the power and capacity from the Ginna plant into theISO-NY consistent with the technical provisions of the RSSA.
On March 22, 2016, Ginna submitted a compliance filing with FERC with revisions to the RSSA requested by FERC. On April 8, 2016, FERC accepted the compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA. Because all regulatory approvals for the RSSA have now been received,with a term expiring on March 31, 2017. In April 2016, Generation began recognizing revenue based on the final approved pricing contained in the RSSA. GenerationRSSA and also recognized aone-time revenue adjustment in April 2016 of approximately $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date through March 31, 2016. A 49.99% portion of theone-time adjustment will bewas removed from Generation’s results of operations as a result of the noncontrolling interests in CENG.
The RSSA approved by the regulatory authorities has a term expiring on March 31, 2017, subject to possible extension in the event that RG&E needs additional time to complete transmission upgrades to address reliability concerns. In March 2016, RG&E notified Ginna that RG&E expects to complete the transmission upgrades prior to the RSSA expiration in March 2017 and will not need Ginna as an ongoing reliability solution after that date.
The approved RSSA requiresrequired Ginna to continue operating through the RSSA term. If Ginna does not plan to retire shortly after the expiration of the RSSA, Ginna is required to file a notice to that effect with the NYPSC no
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
later than September 30, 2016. Under the terms of the RSSA, if Ginna continues to operate after June 14, 2017, Ginna would be required to make certain refund payments up to a maximum of $20 million to RG&E related to capital expenditures. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the CES. As a result, Ginna has reservedstated previously, on November 18, 2016 the right to withdraw this notification and cease commercial operations if the ZEC program is terminated, suspended, or stayed prior to commencement of the program on April 1, 2017 or if for any reason arequired contract with NYSERDA in a form and substance satisfactory towas executed by Generation and CENG for Ginna. Upon the expiry of the RSSA on March 31, 2017, Ginna is not executedrequired to make refund payments of $20 million to RG&E related to capital expenditures. Ginna has been deferring recognition for a portion of the monthly revenue received under the RSSA related to this obligation, and Ginna Nine Mile Point,expects to pay RGE the $20 million in June 2017. Additionally, the provisions of the RSSA provided for aone-time payment of $12 million to be paid from RGE to Ginna at the end of the contract. This $12 million was recognized in revenue as of March 31, 2017. Subject to prevailing over any administrative or FitzPatrick. Negotiations with NYSERDA are ongoing and contract executionlegal challenges, it is currently targeted for completion inexpected the fourth quarter of 2016.
There remains an increased risk that, for economic reasons,CES will allow Ginna could be retired beforeto continue to operate through the end of its current operating license period in 2029. In the event the plant were to be retired before the current license term ends in 2029, Exelon’s and Generation’s results of operations could be adversely affected by the accelerated future decommissioning costs, severance costs, increased depreciation rates, and impairment charges, among other items. See Note7-Early Nuclear Plant Retirements for further information regarding the impacts of a decision to early retire one or more nuclear plants.
Federal Regulatory Matters
Transmission Formula Rate (Exelon, ComEd BGE, PHI, Pepco, DPL and ACE)BGE). ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year. ComEd, BGE, Pepco, DPL, and ACE record regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement in effect and ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s best estimate of the revenue requirement expected to be filed with the FERC for that year’s reconciliation. The regulatory asset associated with transmission true-up is amortized to Operating revenues within their Consolidated Statements of Operations of Comprehensive Income as the associated amounts are recovered through rates.
The following total increases/(decreases) were included in ComEd’s BGE’s, Pepco’s, DPL’s and ACE’sBGE’s electric transmission formula rate filings:
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Annual Transmission Filings(a) | ComEd | BGE | Pepco | DPL | ACE | |||||||||||||||
Initial revenue requirement increase | $ | 90 | $ | 12 | $ | 2 | $ | 8 | $ | 8 | ||||||||||
Annual reconciliation (decrease) increase | 4 | 3 | (10 | ) | (10 | ) | (14 | ) | ||||||||||||
Dedicated facilities (decrease) increase(b) | — | 13 | — | — | — | |||||||||||||||
MAPP abandonment recovery decrease(c) | — | — | (15 | ) | (12 | ) | — | |||||||||||||
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Total revenue requirement increase (decrease) | $ | 94 | $ | 28 | $ | (23 | ) | $ | (14 | ) | $ | (6 | ) | |||||||
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Allowed return on rate base(d) | 8.47 | % | 8.09 | % | 7.88 | % | 7.21 | % | 7.83 | % | ||||||||||
Previously authorized allowed return on rate base(d) | 8.61 | % | 8.46 | % | 8.36 | % | 7.80 | % | 8.51 | % | ||||||||||
Allowed ROE(e) | 11.50 | % | 10.50 | % | 10.50 | % | 10.50 | % | 10.50 | % |
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Annual Transmission Filings(a) | ComEd | BGE | ||||||
Initial revenue requirement increase | $ | 44 | $ | 31 | ||||
Annual reconciliation (decrease) increase | (33 | ) | 3 | |||||
Dedicated facilities decrease(b) | — | (8 | ) | |||||
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Total revenue requirement increase | $ | 11 | $ | 26 | ||||
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Allowed return on rate base(c) | 8.43 | % | 7.47 | % | ||||
Allowed ROE(d) | 11.50 | % | 10.50 | % |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(a) | All rates are effective June 2017, subject to review by the FERC and other parties, which is due by fourth quarter 2017. |
(b) | BGE’s transmission revenues include a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE. |
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As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, |
For additional information regarding ComEd and BGE’s transmission formula rate filings see Note 3 —Regulatory Matters of the Exelon 2015 Form 10-K. For additional information regarding Pepco, DPL and ACE’s transmission formula rate filings see Note 7 — Regulatory Matters of the PHI 2015Exelon 2016 Form10-K.
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 would be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. PECO cannot predict how much, if any, of a transmission rate increase FERC may approve or when the rate increase may go into effect.
PJM Transmission Rate Design and Operating Agreements (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO, BGE, Pepco, DPL and ACE incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of new transmission facilities based on those who benefit from those facilities. In April 2007, FERC issued an order concluding that PJM’s current rate design for existing facilities is just and reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM footprint and that the costs of new facilities less than 500 kV should be allocated to the customers of the new facilities who caused the need for those facilities. A number of parties appealed to the U.S. Court of Appeals for the Seventh Circuit for review of the decision.
In August 2009, the court issued its decision affirming the FERC’s order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above (Cost Allocation Issue) for further consideration by the FERC. On remand, FERC reaffirmed its earlier decision to socialize the costs of new facilities 500 kV and above. A number of parties filed appeals of these orders. In June 2014, the court again remanded the Cost Allocation Issue to FERC. On December 18, 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the Cost Allocation Issue. On June 15, 2016, a number of parties, including Exelon and the Utility Registrants filed an Offer ofa proposed Settlement with FERC. If the Settlement is approved, 50% of the costs of the 500 kV and above facilities approved by the PJM Board on or before February 1, 2013 will be socialized across PJM and 50% will be allocated according to a formula that calculates the flows on the transmission facilities. Each state that is a party in this proceeding either signed, or willdid not oppose, the settlement. On July 5, 2016,The Settlement is opposed by a number of merchant transmission owners and load servicing entities opposed the Settlement in whole or in part. As of September 30, 2016, the Settlement is awaiting FERC’s action. If the Settlement is approved, effective January 1, 2016, for the costs of the 500 kV facilities approved by the PJM Board on or after February 1, 2013, 50% will be socialized across PJM and 50% will be allocated according to an engineering formula that calculates the flows on the transmission facilities.New York load-serving entities. The Settlement includes provisions for monthly credits or charges that are expected to be mostly refunded or recovered through customer rates over a10-year period based on negotiated numbers for charges prior to January 1, 2016.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Exelon expects that the Settlement will not have a material impact on the results of operations, cash flows and financial position of Generation, ComEd, PECO, BGE, Pepco, DPL or ACE. The Settlement is subject to approval by FERC.
Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs (Exelon and Generation). PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to remove the revenues it receives through a federal, state or other 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 resources. Exelon has generally opposed policies that require subsidies or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid. Thus, Exelon has supported a MOPR as a means of minimizing the detrimental impact certain subsidized resources could have on capacity markets (such as the New Jersey (LCAPP) and Maryland (CfD) programs). However, in Exelon’s view, MOPRs should not be applied to resources that receive compensation for providing superior reliability or environmental benefits.
On January 9, 2017, the Electric Power Supply Association (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. Both filings allege that the relevant MOPR should be expanded to also apply to existing resources receiving ZEC compensation under the New York CES and Illinois ZES programs. Exelon has filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS that have generally not been subject to a MOPR. However, if successful, for Generation’s facilities expected to receive ZEC compensation (Quad Cities, Ginna, Nine Mile Point and FitzPatrick), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in those auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any such mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. The timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.
Operating License Renewals (Exelon and Generation). Generation has 40-year operating licenses from the NRC for each of its nuclear units. The operating license renewal process takes approximately four to five years from the commencement of the renewal process until completion of the NRC’s review.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
On December 9, 2014, Generation submitted an application to the NRC to extend the current operating licenses of LaSalle Units 1 and 2 by 20 years. On October 19, 2016, the NRC approved Generation’s request to extend the operating licenses of LaSalle Unit 1 and 2 by 20 years to 2042 and 2043, respectively.
On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a46-year 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 with Maryland Department of the Environment (MDE) for Conowingo, Generation continues to work with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. In addition, Generation continues to work with MDE and other Federal and Maryland state agencies to conduct and fund an additional sediment and nutrient monitoring study.
On August 7, 2015, US Fish and Wildlife Service of the US Department of the Interior (Interior) submitted its modified fishway prescription to FERC in the Conowingo licensing proceedings. On September 11, 2015, Exelon filed a request for an administrative hearing and proposed an alternative prescription to challenge Interior’s preliminary prescription. On April 21, 2016, Exelon and Interior executed a Settlement Agreement resolving all fish passage issues between the parties. Accordingly, on April 22, 2016, Exelon withdrew its Request for a Trial-Type Hearing and Alternative Prescription. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the46-year life of the new license, including both capital and operating costs. The actual timing and amount of these costs are not currently fixed and may vary significantly from year to year throughout the life of the new license. Resolution of the remaining issues relating to Conowingo involving various stakeholders may have a material effect on Exelon’s and Generation’s results of operations and financial
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
position through an increase in capital expenditures and operating costs. As of September 30, 2016, $27March 31, 2017, $29 million of direct costs associated with the Conowingo licensing effortefforts have been capitalized. See Note 3 — Regulatory Matters of the Exelon 20152016 Form10-K for additional information on Generation’s operating license renewal efforts.
Regulatory Assets and Liabilities (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE each prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.
As a result of applying the acquisition method of accounting and pushing it down to the consolidated financial statements of PHI, certain regulatory assets and liabilities were established at Exelon and PHI to offset the impacts of fair valuing the acquired assets and liabilities assumed which are subject to regulatory recovery. In total, Exelon and PHI recorded a net $2.4 billion regulatory asset reflecting adjustments recorded as a result of the acquisition method of accounting. See Note 4 — Mergers, Acquisitions and Dispositions for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of September 30, 2016March 31, 2017 and December 31, 2015.2016. For additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 20152016 Form 10-K and Note 7 — Regulatory Matters of the PHI 2015 Form 10-K.
Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
September 30, 2016 | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
March 31, 2017 | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pension and other postretirement benefits(a) | $ | 4,096 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 4,152 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||
Deferred income taxes(b) | 1,973 | 73 | 1,555 | 94 | 251 | 162 | 38 | 51 | 2,055 | 76 | 1,617 | 101 | 261 | 169 | 40 | 52 | ||||||||||||||||||||||||||||||||||||||||||||||||
AMI programs | 704 | 160 | 53 | 235 | 256 | 171 | 85 | — | 689 | 165 | 46 | 225 | 253 | 170 | 83 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Under-recovered distribution service costs | 232 | 232 | — | — | — | — | — | — | 211 | 211 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Debt costs | 126 | 43 | 1 | 7 | 82 | 18 | 9 | 6 | 122 | 41 | 1 | 7 | 80 | 17 | 9 | 6 | ||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of long-term debt | 828 | — | — | — | 684 | — | — | — | 797 | — | — | — | 658 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of PHI’s unamortized energy contracts | 1,206 | — | — | — | 1,206 | — | — | — | 1,021 | — | — | — | 1,021 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Severance | 6 | — | — | 6 | — | — | — | — | 4 | — | — | 4 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Asset retirement obligations | 108 | 74 | 22 | 11 | 1 | 1 | — | — | 116 | 82 | 22 | 12 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
MGP remediation costs | 295 | 267 | 27 | 1 | — | — | — | — | 296 | 271 | 25 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Under-recovered uncollectible accounts | 58 | 58 | — | — | — | — | — | — | 63 | 63 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Renewable energy | 246 | 244 | — | — | 2 | — | — | 2 | 285 | 282 | — | — | 3 | — | 1 | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||
Energy and transmission programs(h)(i)(j)(k)(l) | 74 | 31 | — | 25 | 18 | 1 | 8 | 9 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy and transmission programs(d)(e)(f)(g)(h)(i) | 71 | 18 | — | 19 | 34 | 6 | 5 | 23 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred storm costs | 39 | — | — | 1 | 38 | 14 | 5 | 19 | 39 | — | — | 1 | 38 | 12 | 7 | 19 | ||||||||||||||||||||||||||||||||||||||||||||||||
Electric generation-related regulatory asset | 13 | — | — | 13 | — | — | — | — | 8 | — | — | 8 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Rate stabilization deferral | 25 | — | — | 25 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy efficiency and demand response programs | 642 | — | 1 | 289 | 352 | 254 | 98 | — | 596 | — | 1 | 269 | 326 | 241 | 84 | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||
Merger integration costs(m)(n) | 23 | — | — | 10 | 13 | 10 | 3 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under-recovered revenue decoupling(o)(p) | 9 | — | — | — | 9 | 7 | 2 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Merger integration costs(j)(k) | 32 | — | — | 8 | 24 | 11 | 13 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under-recovered revenue decoupling(l) | 76 | — | — | 31 | 45 | 36 | 9 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
COPCO acquisition adjustment | 9 | — | — | — | 9 | — | 9 | — | 7 | — | — | — | 7 | — | 7 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Recoverable Workers compensation and long-term disability cost | 30 | — | — | — | 30 | 30 | — | — | 33 | — | — | — | 33 | 33 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Vacation accrual | 37 | — | 13 | — | 24 | — | 14 | 10 | 42 | — | 17 | — | 25 | — | 15 | 10 | ||||||||||||||||||||||||||||||||||||||||||||||||
Securitized stranded costs | 153 | — | — | — | 153 | — | — | 153 | 123 | — | — | — | 123 | — | — | 123 | ||||||||||||||||||||||||||||||||||||||||||||||||
CAP arrearage | 7 | — | 7 | — | — | — | — | — | 11 | — | 11 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Removal costs | 448 | — | — | — | 448 | 119 | 84 | 246 | 486 | — | — | — | 486 | 136 | 90 | 261 | ||||||||||||||||||||||||||||||||||||||||||||||||
Other | 45 | 10 | 9 | 5 | 19 | 11 | 4 | 5 | 46 | 6 | 8 | 5 | 27 | 21 | 4 | 4 | ||||||||||||||||||||||||||||||||||||||||||||||||
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Total regulatory assets | 11,432 | 1,192 | 1,688 | 722 | 3,595 | 798 | 359 | 501 | 11,381 | 1,215 | 1,748 | 690 | 3,444 | 852 | 367 | 501 | ||||||||||||||||||||||||||||||||||||||||||||||||
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Less: current portion | 1,410 | 205 | 37 | 214 | 650 | 122 | 62 | 89 | 1,330 | 183 | 40 | 191 | 653 | 173 | 66 | 94 | ||||||||||||||||||||||||||||||||||||||||||||||||
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Total non-current regulatory assets | $ | 10,022 | $ | 987 | $ | 1,651 | $ | 508 | $ | 2,945 | $ | 676 | $ | 297 | $ | 412 | $ | 10,051 | $ | 1,032 | $ | 1,708 | $ | 499 | $ | 2,791 | $ | 679 | $ | 301 | $ | 407 | ||||||||||||||||||||||||||||||||
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Successor | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
March 31, 2017 | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other postretirement benefits | $ | 48 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear decommissioning | 2,776 | 2,294 | 482 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Removal costs | 1,598 | 1,328 | — | 136 | 134 | 17 | 117 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred rent | 39 | — | — | — | 39 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy efficiency and demand response programs | 185 | 139 | 44 | — | 2 | 2 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
DLC program costs | 8 | — | 8 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric distribution tax repairs | 66 | — | 66 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gas distribution tax repairs | 18 | — | 18 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy and transmission programs(d)(e)(f)(g)(h)(i) | 133 | 38 | 66 | 2 | 27 | 7 | 12 | 8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate stabilization deferral | 3 | — | — | 3 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other | 65 | 4 | 7 | 20 | 34 | 3 | 13 | 17 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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| |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total regulatory liabilities | 4,939 | 3,803 | 691 | 161 | 236 | 29 | 142 | 25 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Less: current portion | 637 | 311 | 161 | 67 | 82 | 10 | 47 | 25 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Totalnon-current regulatory liabilities | $ | 4,302 | $ | 3,492 | $ | 530 | $ | 94 | $ | 154 | $ | 19 | $ | 95 | $ | — | ||||||||||||||||||||||||||||||||||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Successor | ||||||||||||||||||||||||||||||||
September 30, 2016 | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||
Regulatory liabilities | ||||||||||||||||||||||||||||||||
Other postretirement benefits | $ | 85 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
Nuclear decommissioning | 2,704 | 2,238 | 466 | — | — | — | — | — | ||||||||||||||||||||||||
Removal costs | 1,627 | 1,333 | — | 151 | 143 | 20 | 123 | — | ||||||||||||||||||||||||
Deferred rent(q) | 40 | — | — | — | 40 | — | — | — | ||||||||||||||||||||||||
Energy efficiency and demand response programs | 175 | 135 | 40 | — | — | — | — | — | ||||||||||||||||||||||||
DLC program costs | 8 | — | 8 | — | — | — | — | — | ||||||||||||||||||||||||
Electric distribution tax repairs | 79 | — | 79 | — | — | — | — | — | ||||||||||||||||||||||||
Gas distribution tax repairs | 21 | — | 21 | — | — | — | — | — | ||||||||||||||||||||||||
Energy and transmission programs(h)(i)(r)(j)(k)(l) | 171 | 72 | 59 | — | 40 | 17 | 11 | 12 | ||||||||||||||||||||||||
Over-recovered revenue decoupling(o) | 5 | — | — | 5 | — | — | — | — | ||||||||||||||||||||||||
Other | 70 | 3 | 6 | 16 | 45 | 7 | 12 | 24 | ||||||||||||||||||||||||
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Total regulatory liabilities | 4,985 | 3,781 | 679 | 172 | 268 | 44 | 146 | 36 | ||||||||||||||||||||||||
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Less: current portion | 548 | 204 | 128 | 54 | 101 | 20 | 46 | 35 | ||||||||||||||||||||||||
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Total non-current regulatory liabilities | $ | 4,437 | $ | 3,577 | $ | 551 | $ | 118 | $ | 167 | $ | 24 | $ | 100 | $ | 1 | ||||||||||||||||
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Predecessor | ||||||||||||||||||||||||||||||||
December 31, 2015 | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||
Regulatory assets | ||||||||||||||||||||||||||||||||
Pension and other postretirement benefits | $ | 3,156 | $ | — | $ | — | $ | — | $ | 910 | $ | — | $ | — | $ | — | ||||||||||||||||
Deferred income taxes(b) | 1,616 | 64 | 1,473 | 79 | 214 | 137 | 36 | 41 | ||||||||||||||||||||||||
AMI programs | 399 | 140 | 63 | 196 | 267 | 180 | 87 | — | ||||||||||||||||||||||||
Under-recovered distribution service costs(d) | 189 | 189 | — | — | — | — | — | — | ||||||||||||||||||||||||
Debt costs | 47 | 46 | 1 | 8 | 36 | 19 | 10 | 7 | ||||||||||||||||||||||||
Fair value of long-term debt(f) | 162 | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Severance | 9 | — | — | 9 | — | — | — | — | ||||||||||||||||||||||||
Asset retirement obligations | 108 | 67 | 22 | 19 | 1 | 1 | — | — | ||||||||||||||||||||||||
MGP remediation costs | 286 | 255 | 30 | 1 | — | — | — | — | ||||||||||||||||||||||||
Under-recovered uncollectible accounts | 52 | 52 | — | — | — | — | — | — | ||||||||||||||||||||||||
Renewable energy | 247 | 247 | — | — | 6 | — | 1 | 5 | ||||||||||||||||||||||||
Energy and transmission programs(h)(i)(r)(j)(k)(l) | 84 | 43 | 1 | 40 | 33 | 9 | 11 | 13 | ||||||||||||||||||||||||
Deferred storm costs | 2 | — | — | 2 | 43 | 19 | 6 | 18 | ||||||||||||||||||||||||
Electric generation-related regulatory asset | 20 | — | — | 20 | — | — | — | — | ||||||||||||||||||||||||
Rate stabilization deferral | 87 | — | — | 87 | — | — | — | — | ||||||||||||||||||||||||
Energy efficiency and demand response programs | 279 | — | 1 | 278 | 401 | 289 | 111 | 1 | ||||||||||||||||||||||||
Merger integration costs | 6 | — | — | 6 | — | — | — | — | ||||||||||||||||||||||||
Conservation voltage reduction | 3 | — | — | 3 | — | — | — | — | ||||||||||||||||||||||||
Under-recovered revenue decoupling(o)(p) | 30 | — | — | 30 | 14 | 10 | 4 | — | ||||||||||||||||||||||||
COPCO acquisition adjustment | — | — | — | — | — | — | 13 | — | ||||||||||||||||||||||||
Workers compensation and long-term disability costs | — | — | — | — | 31 | 31 | — | — | ||||||||||||||||||||||||
Vacation accrual | 6 | — | 6 | — | 23 | — | 14 | 9 | ||||||||||||||||||||||||
Securitized stranded costs | — | — | — | — | 202 | — | — | 202 | ||||||||||||||||||||||||
CAP arrearage | 7 | — | 7 | — | — | — | — | — | ||||||||||||||||||||||||
Removal costs | — | — | — | — | 369 | 92 | 69 | 208 | ||||||||||||||||||||||||
Other | 29 | 10 | 13 | 3 | 32 | 14 | 9 | 8 | ||||||||||||||||||||||||
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Total regulatory assets | 6,824 | 1,113 | 1,617 | 781 | 2,582 | 801 | 371 | 512 | ||||||||||||||||||||||||
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Less: current portion | 759 | 218 | 34 | 267 | 305 | 140 | 72 | 98 | ||||||||||||||||||||||||
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Total non-current regulatory assets | $ | 6,065 | $ | 895 | $ | 1,583 | $ | 514 | $ | 2,277 | $ | 661 | $ | 299 | $ | 414 | ||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Predecessor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2015 | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2016 | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pension and other postretirement benefits(a) | $ | 4,162 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Deferred income taxes(b) | 2,016 | 75 | 1,583 | 98 | 260 | 171 | 38 | 51 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
AMI programs | 701 | 164 | 49 | 230 | 258 | 174 | 84 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under-recovered distribution service costs(c) | 188 | 188 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt costs | 124 | 42 | 1 | 7 | 81 | 17 | 9 | 6 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of long-term debt | 812 | — | — | — | 671 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of PHI’s unamortized energy contracts | 1,085 | — | — | — | 1,085 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Severance | 5 | — | — | 5 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset retirement obligations | 111 | 76 | 23 | 12 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
MGP remediation costs | 305 | 278 | 26 | 1 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under-recovered uncollectible accounts | 56 | 56 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Renewable energy | 260 | 258 | — | — | 2 | — | — | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy and transmission programs(d)(e)(f)(g)(h)(i) | 89 | 23 | — | 38 | 28 | 6 | 5 | 17 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred storm costs | 36 | — | — | 1 | 35 | 12 | 5 | 18 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric generation-related regulatory asset | 10 | — | — | 10 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate stabilization deferral | 7 | — | — | 7 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy efficiency and demand response programs | 621 | — | 1 | 285 | 335 | 250 | 85 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Merger integration costs(j)(k) | 25 | — | — | 10 | 15 | 11 | 4 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under-recovered revenue decoupling(l) | 27 | — | — | 3 | 24 | 21 | 3 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
COPCO acquisition adjustment | 8 | — | — | — | 8 | — | 8 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Workers compensation and long-term disability costs | 34 | — | — | — | 34 | 34 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Vacation accrual | 31 | — | 7 | — | 24 | — | 14 | 10 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Securitized stranded costs | 138 | — | — | — | 138 | — | — | 138 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
CAP arrearage | 11 | — | 11 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Removal costs | 477 | — | — | — | 477 | 134 | 88 | 255 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other | 49 | 7 | 9 | 5 | 29 | 22 | 5 | 4 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total regulatory assets | 11,388 | 1,167 | 1,710 | 712 | 3,504 | 852 | 348 | 501 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Less: current portion | 1,342 | 190 | 29 | 208 | 653 | 162 | 59 | 96 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Totalnon-current regulatory assets | $ | 10,046 | $ | 977 | $ | 1,681 | $ | 504 | $ | 2,851 | $ | 690 | $ | 289 | $ | 405 | ||||||||||||||||||||||||||||||||||||||||||||||||
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December 31, 2016 | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other postretirement benefits | $ | 94 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 47 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||
Nuclear decommissioning | 2,577 | 2,172 | 405 | — | — | — | — | — | 2,607 | 2,169 | 438 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Removal costs | 1,527 | 1,332 | — | 195 | 150 | 21 | 129 | — | 1,601 | 1,324 | — | 141 | 136 | 18 | 118 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Deferred rent | 39 | — | — | — | 39 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy efficiency and demand response programs | 92 | 52 | 40 | — | 1 | — | — | 1 | 185 | 141 | 41 | — | 3 | 3 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
DLC program costs | 9 | — | 9 | — | — | — | — | — | 8 | — | 8 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Electric distribution tax repairs | 95 | — | 95 | — | — | — | — | — | 76 | — | 76 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Gas distribution tax repairs | 28 | — | 28 | — | — | — | — | — | 20 | — | 20 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Energy and transmission programs(h)(i)(r)(j)(k)(l) | 131 | 53 | 60 | 18 | 27 | 16 | 19 | 8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Over-recovered revenue decoupling(o) | 1 | — | — | 1 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy and transmission programs(d)(e)(f)(g)(h)(i) | 134 | 60 | 56 | — | 18 | 8 | 5 | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other | 16 | 5 | 2 | 8 | 35 | 7 | 12 | 16 | 72 | 4 | 5 | 19 | 41 | 2 | 17 | 20 | ||||||||||||||||||||||||||||||||||||||||||||||||
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Total regulatory liabilities | 4,570 | 3,614 | 639 | 222 | 213 | 44 | 160 | 25 | 4,789 | 3,698 | 644 | 160 | 237 | 31 | 140 | 25 | ||||||||||||||||||||||||||||||||||||||||||||||||
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Less: current portion | 369 | 155 | 112 | 38 | 66 | 15 | 49 | 18 | 602 | 329 | 127 | 50 | 79 | 11 | 43 | 25 | ||||||||||||||||||||||||||||||||||||||||||||||||
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Total non-current regulatory liabilities | $ | 4,201 | $ | 3,459 | $ | 527 | $ | 184 | $ | 147 | $ | 29 | $ | 111 | $ | 7 | $ | 4,187 | $ | 3,369 | $ | 517 | $ | 110 | $ | 158 | $ | 20 | $ | 97 | $ | — | ||||||||||||||||||||||||||||||||
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(a) | As of |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(b) | As of |
(c) |
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As of |
(e) | As of March 31, 2017, PECO’s regulatory liability of $66 million included $41 million related to over-recovered costs under the DSP program, $13 million related to the over-recovered natural gas costs under the PGC, $10 million related to over-recoverednon-bypassable transmission service charges and $2 million related to over-recovered electric transmission costs. As of December 31, 2016, PECO’s regulatory liability of $56 million included $34 million related to over-recovered costs under the DSP program, $10 million related to over-recoverednon-bypassable transmission service charges, $8 million related to the over-recovered natural gas costs under the PGC and $4 million related to the over-recovered electric transmission costs. |
(f) | As of March 31, 2017, BGE’s regulatory asset of $19 million included $3 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $13 million related to under-recovered electric energy costs, and $3 million of abandonment costs to be recovered upon FERC approval. As of March 31, 2017, BGE’s regulatory liability consisted of $2 million related to over-recovered natural gas costs. As of December 31, 2016, BGE’s regulatory asset of $38 million included $4 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $28 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval, and $3 million of under-recovered natural gas costs. |
(g) | As of March 31, 2017, Pepco’s regulatory asset of $6 million included $2 million of transmission costs recoverable through its FERC approved formula rate and $4 million of under-recovered electric energy costs. As of March 31, 2017, Pepco’s regulatory liability of $7 million included $2 million of over-recovered transmission costs and $5 million of over-recovered electric energy costs. As of December 31, 2016, Pepco’s regulatory asset of $6 million related to under-recovered electric energy costs. As of December 31, 2016, Pepco’s regulatory liability of $8 million included $5 million of over-recovered transmission costs and $3 million of over-recovered electric energy costs. |
(h) | As of March 31, 2017, DPL’s regulatory asset of $5 million related to under-recovered electric energy costs. As of March 31, 2017, DPL’s regulatory liability of $12 million included $9 million of over-recovered electric energy costs, $1 million of over-recovered transmission costs, and $2 million of over-recovered gas cost. As of December 31, 2016, DPL’s regulatory asset of $5 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $4 million of under-recovered electric energy costs. As of December 31, 2016, DPL’s regulatory liability of $5 million included $2 million of over-recovered electric energy costs and $3 million of over-recovered transmission costs. |
(i) | As of March 31, 2017, ACE’s regulatory asset of $23 million included $10 million of transmission costs recoverable through its FERC approved formula rate and $13 million of under-recovered electric energy costs. As of March 31, 2017, ACE’s regulatory liability of $8 million included $2 million of over-recovered transmission costs and $6 million of over- |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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As of |
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Represents the electric and natural gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of |
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Capitalized Ratemaking Amounts Not Recognized (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
(DollarsThe following table illustrates our authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes on our Consolidated Balance Sheets. These amounts will be recognized as revenues in millions, except per share data, unless otherwise noted)our 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 | |||||||||||||||||||||||||
March 31, 2017 | $ | 71 | $ | 5 | $ | — | $ | 56 | $ | 10 | $ | 6 | $ | 4 | $ | — | ||||||||||||||||
Exelon | ComEd(a) | PECO | BGE(b) | PHI | Pepco(b) | DPL(b) | ACE | |||||||||||||||||||||||||
December 31, 2016 | $ | 72 | $ | 5 | $ | — | $ | 57 | $ | 10 | $ | 6 | $ | 4 | $ | — |
(a) |
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(b) | BGE’s authorized amounts capitalized for ratemaking purposes related to |
(c) | Pepco’s and DPL’s authorized amounts capitalized for ratemaking purposes related to |
Purchase of Receivables Programs (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
ComEd, PECO, BGE, Pepco, DPL and ACE are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from retail electric and natural gas suppliers that participate in the utilities’ consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and is permitted to recover uncollectible accounts expense, including those from Third Party Suppliers, from customers through distribution rates. ACE purchases receivables at face value. ACE recovers all uncollectible accounts expense, including those from Third Party Suppliers, through the Societal Benefits Charge (SBC) rider, which includes uncollectible accounts expense as a component. The SBC is filed annually with the NJBPU. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
ACE do not record unbilled commodity receivables under the POR programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of September 30, 2016March 31, 2017 and December 31, 2015.2016.
Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of September 30, 2016 | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2017 | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased receivables | $ | 396 | $ | 123 | $ | 90 | $ | 66 | $ | 117 | $ | 79 | $ | 12 | $ | 26 | $ | 305 | $ | 85 | $ | 72 | $ | 59 | $ | 89 | $ | 58 | $ | 10 | $ | 21 | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts(a) | (36 | ) | (17 | ) | (7 | ) | (6 | ) | (6 | ) | (4 | ) | — | (2 | ) | (36 | ) | (14 | ) | (7 | ) | (4 | ) | (11 | ) | (6 | ) | (2 | ) | (3 | ) | |||||||||||||||||||||||||||||||||
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Purchased receivables, net | $ | 360 | $ | 106 | $ | 83 | $ | 60 | $ | 111 | $ | 75 | $ | 12 | $ | 24 | $ | 269 | $ | 71 | $ | 65 | $ | 55 | $ | 78 | $ | 52 | $ | 8 | $ | 18 | ||||||||||||||||||||||||||||||||
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As of December 31, 2015 | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased receivables(b)(c) | $ | 229 | $ | 103 | $ | 67 | $ | 59 | $ | 100 | $ | 70 | $ | 11 | $ | 19 | ||||||||||||||||||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts(a) | (31 | ) | (16 | ) | (7 | ) | (8 | ) | (6 | ) | (4 | ) | — | (2 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||
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Purchased receivables, net | $ | 198 | $ | 87 | $ | 60 | $ | 51 | $ | 94 | $ | 66 | $ | 11 | $ | 17 | ||||||||||||||||||||||||||||||||||||||||||||||||
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Successor | ||||||||||||||||||||||||||||||||
As of December 31, 2016 | Exelon | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||
Purchased receivables(b) | $ | 313 | $ | 87 | $ | 72 | $ | 59 | $ | 95 | $ | 63 | $ | 10 | $ | 22 | ||||||||||||||||
Allowance for uncollectible accounts(a) | (37 | ) | (14 | ) | (6 | ) | (4 | ) | (13 | ) | (7 | ) | (2 | ) | (4 | ) | ||||||||||||||||
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Purchased receivables, net | $ | 276 | $ | 73 | $ | 66 | $ | 55 | $ | 82 | $ | 56 | $ | 8 | $ | 18 | ||||||||||||||||
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(a) | For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing tariff. |
(b) |
|
Pepco’s electric POR program in Maryland included a discount on purchased receivables ranging from 0% to 2% depending on customer class, and Pepco’s electric POR program in the District of Columbia included a discount on purchased receivables ranging from 0% to 6% depending on customer class. DPL’s electric POR program in Maryland included a discount on purchased receivables ranging from 0% to 1% depending on customer class. |
6. Impairment of Long-Lived Assets (Exelon and Generation)
Long-Lived Assets (Exelon and Generation)
Generation evaluates long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. During the first quarter of 2016, significant changes in Generation’s intended use of the Upstream oil and gas assets, developments with nonrecourse debt held by its upstream subsidiary CEU Holdings, LLC (as described in Note 1014 — Debt and Credit Agreements)Agreements of the Exelon 2016 Form10-K) and continued declines in both production volumes and commodity prices suggested that the carrying value may be impaired. Generation concluded that the estimated
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
undiscounted future cash flows and fair value of its Upstream properties were less than their carrying values. As a result, apre-tax impairment charge of $119 million was recorded in March 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. On June 16, 2016, Generation initiated the sales process of its Upstream business by executing a forbearance agreement with the lenders of the nonrecourse debt, see Note 10 — Debt and Credit Agreements for additional information. As a result, the Upstream assets and liabilities are classified as held for sale on Exelon’s and Generation’s Consolidated Balance Sheets at September 30, 2016. See Note 4 — Mergers, Acquisitions and Dispositions for additional information.debt. An additionalpre-tax impairment charge of $15 million was recorded in September 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income due to further declines in fair value.
Further declines in commodity prices or further developments with Generation’s intended use or disposition of the assets could potentially result in future impairments In December 2016, Generation sold substantially all of the Upstream assets.
Generation evaluates long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In the second quarter of 2016, updates to the Company’s long-term view of energyAssets. See Note 4 — Merger, Acquisitions, and capacity prices suggested that the carrying value of a group of merchant wind assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair valueDispositions of the group were less than their carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result of the fair value analysis, long-lived merchant wind assets held and used with a carrying amount of approximately $60 million were written down to their fair value of $24 million and a pre-tax impairment charge of $36 million was recorded during the second quarter in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Also in the second quarter ofExelon 2016 updates to the Company’s long-term view, as described above, in conjunction with the retirement announcements of the Quad Cities and Clinton nuclear plants in Illinois suggested that the carrying value of our Midwest asset group may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows of the Midwest asset group and no impairment charge was required.Form10-K for further information.
Like-Kind Exchange Transaction (Exelon)
In June 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon Corporation, entered into transactions pursuant to which UII invested in coal-fired generating station leases (Headleases) with the Municipal Electric Authority of Georgia (MEAG). The generating stations were leased back to MEAG as part of the transactions (Leases).
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
On March 31, 2016, UII and MEAG finalized an agreement to terminate the MEAG Headleases, the MEAG Leases, and other related agreements prior to their expiration dates. As a result of the lease termination, UII received an early termination payment of $360 million from MEAG andwrote-off the $356 million net investment in the MEAG Headleases and the Leases. The transaction resulted in apre-tax gain of $4 million which is reflected in Operating and maintenance expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income. See Note 11 — Income Taxes for additional information.
7. Early Nuclear Plant Retirements (Exelon and Generation)
Exelon and Generation continue to evaluate the current and expected economic value of each of Generation’s nuclear plants. Factors that will continue to affect the economic value of Generation’s nuclear plants include, but are not limited to: market power prices, results of capacity auctions, potential legislative and
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
regulatory solutions to ensure nuclear plants are fairly compensated for their carbon-free emissions, and the impact of finalpotential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules.
In 2015 and 2016, Generation identified the Clinton, Quad Cities, ClintonGinna, Nine Mile Point, and GinnaThree Mile Island (TMI) nuclear plants as having the greatest risk of early retirement based on economic valuation and other factors. At that time,PSEG has also recently made public similar financial challenges facing its New Jersey nuclear plants including Salem, of which Generation owns a 42.59% ownership interest. As previously disclosed, Exelon and Generation deferred retirement decisions on Clinton and Quad Cities until 2016 in orderhave committed to participate incease operation of the 2016-2017 MISO primary reliability auction andOyster Creek nuclear plant by the 2019-2020 PJM capacity auctions held in April and May 2016, respectively, as well as to provide Illinois policy makers with additional time to consider needed reforms and for MISO to consider market design changes to ensure long-term power system reliability in southern Illinois.
In April 2016, Clinton cleared the MISO primary reliability auction as a price taker for the 2016-2017 planning year. The resulting capacity price is insufficient to cover cash operating costs and a risk-adjusted rateend of return to shareholders. In May 2016, Quad Cities did not clear in the PJM capacity auction for the 2019-2020 planning year and will not receive capacity revenue for that period.2019.
Based on theseinsufficient capacity auction results and given the lack of progress on Illinois energy legislation, and MISO market reforms, on June 2, 2016, Generation announced it will move forwarda decision to shut down the Clinton and Quad Cities nuclear plants on June 1, 2017 and June 1, 2018, respectively. The current Nuclear Regulatory Commission (NRC) licensesWith the passage of the Illinois ZES on December 7, 2016, and subject to prevailing over any related administrative or legal challenges, Generation reversed this decision and revised the expected economic useful lives for both facilities; 2027 for Clinton and 2032 for Quad Cities expire in 2026Cities. Refer to Note 5—Regulatory Matters for additional discussion on the Illinois ZES.
Exelon’s and 2032, respectively. Generation is proceedingGeneration’s 2016 results included a net incremental $714 million of totalpre-tax expense associated with the market and regulatory notifications that must be made to shut down the plants, including notification to the NRC on June 20, 2016, and filing of a deactivation notice with PJM for Quad Cities on July 6, 2016. Generation will formally notify MISO of its plans to close Clinton later this year.
In 2016, as a result of the plantinitial early retirement decision for Clinton and Quad Cities, Exelon and Generation recognized one-time charges in Operating and maintenance expense of $146 million related to materials and supplies inventory reserve adjustments, employee-related costs and construction work-in-progress (CWIP) impairments, among other items. In addition to these one-time charges, there will be ongoing annual incremental non-cash charges to earnings stemming from shortening the expected economic useful life of Clinton and Quad Cities primarily related to accelerated depreciation of plant assets (including any asset retirement costs (ARC)), accelerated amortization of nuclear fuel, and additional asset retirement obligation (ARO) accretion expense associated with the changes in decommissioning timing and cost assumptions. Through September 30, 2016, Exelon’s and Generation’s results include an incremental $443 million of pre-tax expense for these items as summarized in the table below. Please refer to Note 12 — Nuclear Decommissioning for additional detail on changes to the Nuclear decommissioning ARO balances resulting from the early retirement of Clinton and Quad Cities.
Income statement expense (pre-tax) | September 30, 2016 | |||
Depreciation and Amortization | ||||
Accelerated depreciation(a) | $ | 459 | ||
Accelerated nuclear fuel amortization | 37 | |||
Operating and Maintenance | ||||
Increase ARO accretion, net of contractual offset(b) | 2 | |||
Contractual offset for ARC depreciation(b) | (55 | ) | ||
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| |||
Total | $ | 443 | ||
|
|
Income statement expense(pre-tax) | Q2 2016 | Q3 2016 | Q4 2016 | YTD 2016 | ||||||||||||
Depreciation and amortization | ||||||||||||||||
Accelerated depreciation(a) | $ | 115 | $ | 344 | $ | 253 | $ | 712 | ||||||||
Accelerated Nuclear Fuel amortization | 9 | 28 | 23 | 60 | ||||||||||||
Operating and maintenance | ||||||||||||||||
One time charges(b) | 141 | 5 | (120 | ) | 26 | |||||||||||
ARO accretion, net of contractual offset(c) | — | 2 | — | 2 | ||||||||||||
Contractual offset for ARC depreciation(c) | (14 | ) | (41 | ) | (31 | ) | (86 | ) | ||||||||
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Total | $ | 251 | $ | 338 | $ | 125 | $ | 714 |
(a) |
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(b) | Primarily included materials and supplies inventory reserve adjustments, employee related costs and constructionwork-in-progress (CWIP) impairments. |
(c) | For Quad Cities based on the regulatory agreement with the Illinois Commerce Commission, decommissioning-related activities are offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The Three Mile Island (TMI) nuclear plant also did not clear in the May 2016 PJM capacity auction for the 2019-2020 planning year and will not receive capacity revenue for that period. This is the second consecutive year that TMI failed to clear the capacity auction. Although the plant is committed to operate through May 2019, the plant faces continued economic challenges and Exelon and Generation are exploring all options to return it to profitability. While a portion of the Byron nuclear plant’s capacity did not clear the PJM 2019-2020 planning year capacity auction, the plant is committed to run through May 2020. The company’s other nuclear plants in PJM cleared in the auction, except Oyster Creek, which did not participate in the auction given Exelon’s and Generation’s previous commitment to cease operation of the Oyster Creek nuclear plant by the end of 2019.
In New York, the Ginna, and Nine Mile Point, and Generation’s recently acquired FitzPatrick nuclear plants continue to faceplant also faced significant economic challenges and risk of retirement before the end of each unit’s respective operating license period (2029 for Ginna and Nine Mile Point Unit 1, and 2046 for Nine Mile Point Unit 2)2, and 2034 for FitzPatrick). On August 1, 2016, the NYPSC issued an order adopting the Clean Energy Standard (CES), which would provide payments to Ginna and Nine Mile Point for the environmental attributes of their production. Subject to Ginna and Nine Mile Point entering into a satisfactory contract with the NYSERDA, as required under the CES andthat, subject to prevailing over any administrative or legal challenges, the CES willwould allow Ginna, and Nine Mile Point, and FitzPatrick to continue to operate at least through the life of the program (March 31, 2029). The approved RSSA currently requires Ginna to continue operatingassumed useful life for depreciation purposes for each facility is through the end of their current operating licenses. Ginna most recently operated under an RSSA term expiring inwhich expired March 2017. If Ginna does not plan to retire shortly after the expiration of the RSSA, notification to that effect was required to be filed with the NYPSC no later than September 30, 2016. On September 30, 2016, Ginna31, 2017 and has filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful executionRSSA. Refer to Note 4 — Mergers, Acquisitions and Dispositions for additional information on Generation’s acquisition of an agreement between GinnaFitzPatrick and NYSERDA for the sale of ZECs under the CES. Negotiations with NYSERDA are ongoing and contract execution is currently targeted for completion in the fourth quarter of 2016. Refer to Note 5 — Regulatory Matters for additional discussion on the Ginna RSSA and the New York CES.
Assuming the successful implementation of the Illinois ZES and the New York CES and the continued effectiveness of these programs, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to the extent either the Illinois ZES or the New York CES programs do not operate as expected over their full terms, each of these plants (and now including the newly acquired FitzPatrick) could again be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future results of operations, cash flows and financial position.
The TMI nuclear plant did not clear in the May 2016 PJM capacity auction for the 2019-2020 planning year and will not receive capacity revenue for that period, the second consecutive year that TMI failed to clear the PJM base residual capacity auction. The plant is currently committed to operate through May 2019. TMI will be offered into the May 2017 PJM capacity auction for the 2020-2021 planning year, however the plant faces continued economic challenges and Exelon and Generation are exploring all options to return it to profitability, including the potential for a legislative solution in Pennsylvania similar to that passed in Illinois.
The following table provides the balance sheet amounts as of September 30, 2016March 31, 2017 for significant assets and liabilities associated with TMI, the three nuclear plantsplant currently considered by management to be at the greatest risk of early retirement due to current economic valuations and other factors.
(in millions) | TMI | Ginna | NMP | TMI | ||||||||||||
Asset Balances | ||||||||||||||||
Materials and supplies inventory | $ | 39 | $ | 31 | $ | 70 | $ | 40 | ||||||||
Nuclear fuel inventory, net | 93 | 41 | 214 | 72 | ||||||||||||
Completed plant, net | 956 | 124 | 1,151 | 1,000 | ||||||||||||
Construction work in progress | 38 | 13 | 53 | 40 | ||||||||||||
Liability Balances | ||||||||||||||||
Asset retirement obligation | (492 | ) | (667 | ) | (780 | ) | (572 | ) | ||||||||
NRC License Renewal Term | 2034 | 2029 | 2029 (unit 1 | ) | 2034 | |||||||||||
2046 (unit 2 | ) |
Assuming the successful implementation of the CES and its continued effectiveness, Generation and CENG would no longer consider Ginna and Nine Mile Point to be at heightened risk of early retirement; however, absent the CES for the full expected duration they will remain at heightened risk. The precise timing of an early retirement date for any of these plants,nuclear plant, and the resulting financial statement impacts, may be affected by a number of factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of anyco-owner
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
requirements and stipulations, and decommissioning trust fund requirements, 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, where applicable, and just prior to its next scheduled nuclear refueling outage.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)8. Fair Value of Financial Assets and Liabilities (All Registrants)
(Dollars in millions, except per share data, unless otherwise noted)
|
Fair Value of Financial Liabilities Recorded at the Carrying Amount
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) and preferred stock as of September 30, 2016March 31, 2017 and December 31, 2015:2016:
Exelon
September 30, 2016 | March 31, 2017 | |||||||||||||||||||||||||||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||
Short-term liabilities | $ | 567 | $ | — | $ | 567 | $ | — | $ | 567 | $ | 2,048 | $ | — | $ | 2,048 | $ | — | $ | 2,048 | ||||||||||||||||||||
Long-term debt (including amounts due within one year)(a) | 34,842 | 1,075 | 34,272 | 2,279 | 37,626 | 34,689 | 1,135 | 32,562 | 1,962 | 35,659 | ||||||||||||||||||||||||||||||
Long-term debt to financing trusts(b) | 642 | — | — | 692 | 692 | 641 | — | — | 677 | 677 | ||||||||||||||||||||||||||||||
SNF obligation | 1,023 | — | 856 | — | 856 | 1,136 | — | 813 | — | 813 | ||||||||||||||||||||||||||||||
December 31, 2015 | ||||||||||||||||||||||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||||||
Short-term liabilities | $ | 536 | $ | 3 | $ | 533 | $ | — | $ | 536 | ||||||||||||||||||||||||||||||
Long-term debt (including amounts due within one year)(a) | 25,145 | 931 | 23,644 | 1,349 | 25,924 | |||||||||||||||||||||||||||||||||||
Long-term debt to financing trusts(b) | 641 | — | — | 673 | 673 | |||||||||||||||||||||||||||||||||||
SNF obligation | 1,021 | — | 818 | — | 818 |
December 31, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 1,267 | $ | — | $ | 1,267 | $ | — | $ | 1,267 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 34,005 | 1,113 | 31,741 | 1,959 | 34,813 | |||||||||||||||
Long-term debt to financing trusts(b) | 641 | — | — | 667 | 667 | |||||||||||||||
SNF obligation | 1,024 | — | 732 | — | 732 |
Generation
September 30, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 40 | $ | — | $ | 40 | $ | — | $ | 40 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 9,255 | — | 8,015 | 1,684 | 9,699 | |||||||||||||||
SNF obligation | 1,023 | — | 856 | — | 856 | |||||||||||||||
December 31, 2015 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 29 | $ | — | $ | 29 | $ | — | $ | 29 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 8,959 | — | 7,767 | 1,349 | 9,116 | |||||||||||||||
SNF obligation | 1,021 | — | 818 | — | 818 |
ComEd
March 31, 2017 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 717 | $ | — | $ | 717 | $ | — | $ | 717 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 9,979 | — | 8,200 | 1,671 | 9,871 | |||||||||||||||
SNF obligation | 1,136 | — | 813 | — | 813 |
September 30, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 10 | $ | — | $ | 10 | $ | — | $ | 10 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 7,031 | — | 8,081 | — | 8,081 | |||||||||||||||
Long-term debt to financing trusts(b) | 205 | — | — | 218 | 218 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
December 31, 2015 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 294 | $ | — | $ | 294 | $ | — | $ | 294 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 6,509 | — | 7,069 | — | 7,069 | |||||||||||||||
Long-term debt to financing trusts(b) | 205 | — | — | 213 | 213 |
PECO
September 30, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Long-term debt (including amounts due within one year)(a) | $ | 2,879 | $ | — | �� | $ | 3,266 | $ | — | $ | 3,266 | |||||||||
Long-term debt to financing trusts | 184 | — | — | 207 | 207 | |||||||||||||||
December 31, 2015 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Long-term debt (including amounts due within one year)(a) | $ | 2,580 | $ | — | $ | 2,786 | $ | — | $ | 2,786 | ||||||||||
Long-term debt to financing trusts | 184 | — | — | 195 | 195 |
BGE
September 30, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Long-term debt (including amounts due within one year)(a) | $ | 2,662 | $ | — | $ | 2,966 | $ | — | $ | 2,966 | ||||||||||
Long-term debt to financing trusts(b) | 252 | — | — | 267 | 267 | |||||||||||||||
December 31, 2015 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 213 | $ | 3 | $ | 210 | $ | — | $ | 213 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 1,858 | — | 2,044 | — | 2,044 | |||||||||||||||
Long-term debt to financing trusts(b) | 252 | — | — | 264 | 264 |
PHI
September 30, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Successor | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||
Short-term liabilities | $ | 517 | $ | — | $ | 517 | $ | — | $ | 517 | ||||||||||
Long-term debt (including amounts due within one year) | 6,044 | — | 5,698 | 594 | 6,292 |
December 31, 2015 | December 31, 2016 | |||||||||||||||||||||||||||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||||||||||||||||||
Predecessor | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||
Carrying Amount | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||
Short-term liabilities | $ | 958 | $ | — | $ | 958 | $ | — | $ | 958 | $ | — | $ | 699 | $ | — | $ | 699 | ||||||||||||||||||||||
Long-term debt (including amounts due within one year)(a) | 5,279 | — | 5,231 | 586 | 5,817 | 9,241 | — | 7,482 | 1,670 | 9,152 | ||||||||||||||||||||||||||||||
Preferred stock | 183 | — | — | 183 | 183 | |||||||||||||||||||||||||||||||||||
SNF obligation | 1,024 | — | 732 | — | 732 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
ComEd
March 31, 2017 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 365 | $ | — | $ | 365 | $ | — | $ | 365 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 7,035 | — | 7,615 | — | 7,615 | |||||||||||||||
Long-term debt to financing trusts(b) | 205 | — | — | 218 | 218 |
December 31, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Long-term debt (including amounts due within one year)(a) | $ | 7,033 | $ | — | $ | 7,585 | $ | — | $ | 7,585 | ||||||||||
Long-term debt to financing trusts(b) | 205 | — | — | 215 | 215 |
PECO
March 31, 2017 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Long-term debt (including amounts due within one year)(a) | $ | 2,580 | $ | — | $ | 2,806 | $ | — | $ | 2,806 | ||||||||||
Long-term debt to financing trusts | 184 | — | — | 193 | 193 |
December 31, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Long-term debt (including amounts due within one year)(a) | $ | 2,580 | $ | — | $ | 2,794 | $ | — | $ | 2,794 | ||||||||||
Long-term debt to financing trusts | 184 | — | — | 192 | 192 |
BGE
March 31, 2017 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 95 | $ | — | $ | 95 | $ | — | $ | 95 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 2,323 | — | 2,501 | — | 2,501 | |||||||||||||||
Long-term debt to financing trusts(b) | 252 | — | — | 266 | 266 |
December 31, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 45 | $ | — | $ | 45 | $ | — | $ | 45 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 2,322 | — | 2,467 | — | 2,467 | |||||||||||||||
Long-term debt to financing trusts(b) | 252 | — | — | 260 | 260 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
PHI (Successor)
March 31, 2017 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 167 | $ | — | $ | 167 | $ | — | $ | 167 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 5,860 | — | 5,510 | 291 | 5,801 |
December 31, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 522 | $ | — | $ | 522 | $ | — | $ | 522 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 5,898 | — | 5,520 | 289 | 5,809 |
Pepco
September 30, 2016 | ||||||||||||||||||||||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||||||
Long-term debt (including amounts due within one year)(a) | $ | 2,350 | $ | — | $ | 3,000 | $ | 2 | $ | 3,002 | ||||||||||||||||||||||||||||||
December 31, 2015 | March 31, 2017 | |||||||||||||||||||||||||||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||
Short-term liabilities | $ | 64 | $ | — | $ | 64 | $ | — | $ | 64 | $ | 167 | $ | — | $ | 167 | $ | — | $ | 167 | ||||||||||||||||||||
Long-term debt (including amounts due within one year)(a) | 2,351 | — | 2,673 | — | 2,673 | 2,350 | — | 2,804 | 9 | 2,813 |
December 31, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 23 | $ | — | $ | 23 | $ | — | $ | 23 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 2,349 | — | 2,788 | 8 | 2,796 |
DPL
September 30, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 17 | $ | — | $ | 17 | $ | — | $ | 17 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 1,265 | — | 1,277 | 101 | 1,378 | |||||||||||||||
December 31, 2015 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 105 | $ | — | $ | 105 | $ | — | $ | 105 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 1,265 | — | 1,185 | 103 | 1,288 |
March 31, 2017 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Long-term debt (including amounts due within one year)(a) | $ | 1,326 | $ | — | $ | 1,374 | $ | — | $ | 1,374 |
December 31, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Long-term debt (including amounts due within one year)(a) | $ | 1,340 | $ | — | $ | 1,383 | $ | — | $ | 1,383 |
ACE
September 30, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Long-term debt (including amounts due within one year)(a) | $ | 1,167 | $ | — | $ | 1,058 | $ | 299 | $ | 1,357 | ||||||||||
December 31, 2015 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Short-term liabilities | $ | 5 | $ | — | $ | 5 | $ | — | $ | 5 | ||||||||||
Long-term debt (including amounts due within one year)(a) | 1,201 | — | 1,044 | 280 | 1,324 |
March 31, 2017 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Long-term debt (including amounts due within one year)(a) | $ | 1,145 | $ | — | $ | 989 | $ | 282 | $ | 1,271 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
December 31, 2016 | ||||||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||
Long-term debt (including amounts due within one year)(a) | $ | 1,155 | $ | — | $ | 1,007 | $ | 280 | $ | 1,287 |
(a) | Includes unamortized debt issuance costs which are not fair valued of |
(b) | Includes unamortized debt issuance costs which are not fair valued of $7 million, $1 million, and $6 million for Exelon, ComEd and BGE, respectively, as of |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of dividends payable (included in other current liabilities) (Level 1) and short-term borrowings (Level 2). The Registrants’ carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments.
Long-Term Debt. The fair value amounts of Exelon’s taxable debt securities (Level 2) and private placement taxable debt securities (Level 3) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the electric utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. Due to low trading volume of private placement debt, qualitative factors such as market conditions, low volume of investors and investor demand, this debt is classified as Level 3. The fair value of Exelon’s equity units (Level 1) are valued based on publicly traded securities issued by Exelon.
The fair value of Generation’s and PHI’s Pepco’snon-government-backed fixed rate nonrecourse debt (Level 3) is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows oroff-taker credit, and other circumstances related to the project (e.g., political and regulatory environment). The fair value of Generation’s government-backed fixed rate project financing debt (Level 3) is largely based on a discounted cash flow methodology that is similar to the taxable debt securities methodology described above. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable Treasury rate as well as a current market curve derived from government-backed securities. Variable rate project financing debt resets on a monthly or quarterly basis and the carrying value approximates fair value (Level 2). When trading data is available on variable rate project financing debt, the fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles (Level 2). Generation, Pepco, DPL and ACE also havetax-exempt debt (Level 2). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (e.g., conduit issuer political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above. Variable ratetax-exempt debt (Level 2) resets on a regular basis and the carrying value approximates fair value.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
SNF Obligation. The carrying amount of Generation’s SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation estimated to be settled in 2025 is calculated by compounding the current book value of the SNF obligation at the13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2025.2030. This amount also includes $110 million for the fair value of theone-time fee obligation associated with FitzPatrick as of March 31, 2017. The fair value was determined using a similar methodology, however the New York Power Authority’s (NYPA) discount rate is used in place of Generation’s given the contractual right to reimbursement from NYPA for the obligation; see Note 4 — Mergers, Acquisitions and Dispositions for additional information on Generation’s acquisition of FitzPatrick.
Long-Term Debt to Financing Trusts.Exelon’s long-term debt to financing trusts is valued based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Preferred Stock. The fair value of these securities is determined based on the carrying value of the shares per the Subscription Agreement between PHI and Exelon. See Note 16 — Mezzanine Equity for further details.
Recurring Fair Value Measurements
Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
Transfers in and out of levels are recognized as of the end of the reporting period when the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. Additionally, there were no significantmaterial transfers between Level 1 and Level 2 during the ninethree months ended September 30, 2016March 31, 2017 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations. For derivative contracts, transfers into Level 2 from Level 3 generally occur when the contract tenor becomes more observable and due to changes in market liquidity or assumptions for certain commodity contracts.
Generation and Exelon
In accordance with the applicable guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share as a practical expedient are no longer classified within the fair value hierarchy and are included under “Not subject to leveling” in the table below. See Note 2 — New Accounting Pronouncements for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following tables present assets and liabilities measured and recorded at fair value on Exelon’s and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2016March 31, 2017 and December 31, 2015:2016:
Generation | Exelon | Generation | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of September 30, 2016 | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2017 | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | 94 | $ | — | $ | — | $ | — | $ | 94 | $ | 1,645 | $ | — | $ | — | $ | — | $ | 1,645 | $ | 135 | $ | — | $ | — | $ | — | $ | 135 | $ | 342 | $ | — | $ | — | $ | — | $ | 342 | ||||||||||||||||||||||||||||||||||||||||
NDT fund investments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents(b) | 163 | 20 | — | — | 183 | 163 | 20 | — | — | 183 | 160 | 21 | — | — | 181 | 160 | 21 | — | — | 181 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equities | 3,566 | 335 | — | 1,992 | 5,893 | 3,566 | 335 | — | 1,992 | 5,893 | 4,113 | 505 | 1 | 2,089 | 6,708 | 4,113 | 505 | 1 | 2,089 | 6,708 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Corporate debt | — | 1,629 | 257 | — | 1,886 | — | 1,629 | 257 | — | 1,886 | — | 1,749 | 255 | — | 2,004 | — | 1,749 | 255 | — | 2,004 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Treasury and agencies | 1,363 | 33 | — | — | 1,396 | 1,363 | 33 | — | — | 1,396 | 1,516 | 35 | — | — | 1,551 | 1,516 | 35 | — | — | 1,551 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Foreign governments | — | 50 | — | — | 50 | — | 50 | — | — | 50 | — | 57 | — | — | 57 | — | 57 | — | — | 57 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
State and municipal debt | — | 268 | — | — | 268 | — | 268 | — | — | 268 | — | 241 | — | — | 241 | — | 241 | — | — | 241 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other(c) | — | 56 | — | 510 | 566 | — | 56 | — | 510 | 566 | — | 52 | — | 484 | 536 | — | 52 | — | 484 | 536 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fixed income subtotal | 1,363 | 2,036 | 257 | 510 | 4,166 | 1,363 | 2,036 | 257 | 510 | 4,166 | 1,516 | 2,134 | 255 | 484 | 4,389 | 1,516 | 2,134 | 255 | 484 | 4,389 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Middle market lending | — | — | 436 | 23 | 459 | — | — | 436 | 23 | 459 | — | — | 427 | 64 | 491 | — | — | 427 | 64 | 491 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Private equity | — | — | — | 138 | 138 | — | — | — | 138 | 138 | — | — | — | 158 | 158 | — | — | — | 158 | 158 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Real estate | — | — | — | 306 | 306 | — | — | — | 306 | 306 | — | — | — | 427 | 427 | — | — | — | 427 | 427 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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NDT fund investments subtotal(d) | 5,092 | 2,391 | 693 | 2,969 | 11,145 | 5,092 | 2,391 | 693 | 2,969 | 11,145 | 5,789 | 2,660 | 683 | 3,222 | 12,354 | 5,789 | 2,660 | 683 | 3,222 | 12,354 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Pledged assets for Zion Station decommissioning | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | 14 | — | — | — | 14 | 14 | — | — | — | 14 | 21 | — | — | — | 21 | 21 | — | — | — | 21 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equities | — | 1 | — | — | 1 | — | 1 | — | — | 1 | — | 1 | — | — | 1 | — | 1 | — | — | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Treasury and agencies | 28 | 2 | — | — | 30 | 28 | 2 | — | — | 30 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Corporate debt | — | 3 | — | — | 3 | — | 3 | — | — | 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fixed income subtotal | 28 | 5 | — | — | 33 | 28 | 5 | — | — | 33 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fixed income — U.S. Treasury and agencies | 8 | 1 | — | — | 9 | 8 | 1 | — | — | 9 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Middle market lending | — | — | 19 | 68 | 87 | — | — | 19 | 68 | 87 | — | — | 20 | 44 | 64 | — | — | 20 | 44 | 64 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Pledged assets for Zion Station | 42 | 6 | 19 | 68 | 135 | 42 | 6 | 19 | 68 | 135 | 29 | 2 | 20 | 44 | 95 | 29 | 2 | 20 | 44 | 95 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Rabbi trust investments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | 10 | — | — | — | 10 | 83 | — | — | — | 83 | 7 | — | — | — | 7 | 80 | — | — | — | 80 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mutual funds | 19 | — | — | — | 19 | 50 | — | — | — | 50 | 20 | — | — | — | 20 | 53 | — | — | — | 53 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fixed income | — | — | — | — | — | — | 14 | — | — | 14 | — | — | — | — | — | — | 15 | — | — | 15 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Life insurance contracts | — | 18 | — | — | 18 | — | 64 | 21 | — | 85 | — | 20 | — | — | 20 | — | 66 | 20 | — | 86 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Rabbi trust investments subtotal | 29 | 18 | — | — | 47 | 133 | 78 | 21 | — | 232 | 27 | 20 | — | — | 47 | 133 | 81 | 20 | — | 234 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Commodity derivative assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | 883 | 2,790 | 1,948 | — | 5,621 | 884 | 2,790 | 1,948 | — | 5,622 | 749 | 2,993 | 1,631 | — | 5,373 | 751 | 2,993 | 1,631 | — | 5,375 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Proprietary trading | 11 | 51 | 36 | — | 98 | 11 | 51 | 36 | — | 98 | 5 | 50 | 25 | — | 80 | 5 | 50 | 25 | — | 80 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | (927 | ) | (2,527 | ) | (896 | ) | — | (4,350 | ) | (928 | ) | (2,527 | ) | (896 | ) | — | (4,351 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f)(g) | (639 | ) | (2,575 | ) | (873 | ) | — | (4,087 | ) | (641 | ) | (2,575 | ) | (873 | ) | — | (4,089 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Commodity derivative assets subtotal | (33 | ) | 314 | 1,088 | — | 1,369 | (33 | ) | 314 | 1,088 | — | 1,369 | 115 | 468 | 783 | — | 1,366 | 115 | 468 | 783 | — | 1,366 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Derivatives designated as hedging instruments | — | — | — | — | — | — | 39 | — | — | 39 | — | — | — | — | — | — | 12 | — | — | 12 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | — | 28 | — | — | 28 | — | 28 | — | — | 28 | — | 22 | — | — | 22 | — | 22 | — | — | 22 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Proprietary trading | 7 | 1 | — | — | 8 | 7 | 1 | — | — | 8 | 3 | 1 | — | — | 4 | 3 | 1 | — | — | 4 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | (4 | ) | (17 | ) | — | — | (21 | ) | (4 | ) | (17 | ) | — | — | (21 | ) | (4 | ) | (14 | ) | — | — | (18 | ) | (4 | ) | (14 | ) | — | — | (18 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
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Interest rate and foreign currency derivative assets subtotal | 3 | 12 | — | — | 15 | 3 | 51 | — | — | 54 | (1 | ) | 9 | — | — | 8 | (1 | ) | 21 | — | — | 20 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Other investments | — | — | 42 | — | 42 | — | — | 42 | — | 42 | — | — | 40 | — | 40 | — | — | 40 | — | 40 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total assets | 5,227 | 2,741 | 1,842 | 3,037 | 12,847 | 6,882 | 2,840 | 1,863 | 3,037 | 14,622 | 6,094 | 3,159 | 1,526 | 3,266 | 14,045 | 6,407 | 3,232 | 1,546 | 3,266 | 14,451 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation | Exelon | Generation | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of September 30, 2016 | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2017 | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | (1,037 | ) | (2,917 | ) | (1,160 | ) | — | (5,114 | ) | (1,037 | ) | (2,917 | ) | (1,404 | ) | — | (5,358 | ) | (787 | ) | (2,855 | ) | (1,167 | ) | — | (4,809 | ) | (787 | ) | (2,855 | ) | (1,449 | ) | — | (5,091 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Proprietary trading | (10 | ) | (53 | ) | (39 | ) | — | (102 | ) | (10 | ) | (53 | ) | (39 | ) | — | (102 | ) | (6 | ) | (49 | ) | (22 | ) | — | (77 | ) | (6 | ) | (49 | ) | (22 | ) | — | (77 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 1,012 | 2,777 | 1,046 | — | 4,835 | 1,012 | 2,777 | 1,046 | — | 4,835 | 714 | 2,846 | 971 | — | 4,531 | 714 | 2,846 | 971 | — | 4,531 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Commodity derivative liabilities subtotal | (35 | ) | (193 | ) | (153 | ) | — | (381 | ) | (35 | ) | (193 | ) | (397 | ) | — | (625 | ) | (79 | ) | (58 | ) | (218 | ) | — | (355 | ) | (79 | ) | (58 | ) | (500 | ) | — | (637 | ) | ||||||||||||||||||||||||||||||||||||||||||||
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Interest rate and foreign currency derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives designated as hedging instruments | — | (18 | ) | — | — | (18 | ) | — | (18 | ) | — | — | (18 | ) | — | (1 | ) | — | — | (1 | ) | — | (1 | ) | — | — | (1 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | — | (19 | ) | — | — | (19 | ) | — | (19 | ) | — | — | (19 | ) | — | (25 | ) | — | — | (25 | ) | — | (25 | ) | — | — | (25 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Proprietary trading | (6 | ) | — | — | — | (6 | ) | (6 | ) | — | — | — | (6 | ) | (3 | ) | — | — | — | (3 | ) | (3 | ) | — | — | — | (3 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 8 | 16 | — | — | 24 | 8 | 16 | — | — | 24 | 4 | 14 | — | — | 18 | 4 | 14 | — | — | 18 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Interest rate and foreign currency derivative liabilities subtotal | 2 | (21 | ) | — | — | (19 | ) | 2 | (21 | ) | — | — | (19 | ) | 1 | (12 | ) | — | — | (11 | ) | 1 | (12 | ) | — | — | (11 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
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Deferred compensation obligation | — | (32 | ) | — | — | (32 | ) | — | (131 | ) | — | — | (131 | ) | — | (35 | ) | — | — | (35 | ) | — | (135 | ) | — | — | (135 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total liabilities | (33 | ) | (246 | ) | (153 | ) | — | (432 | ) | (33 | ) | (345 | ) | (397 | ) | — | (775 | ) | (78 | ) | (105 | ) | (218 | ) | — | (401 | ) | (78 | ) | (205 | ) | (500 | ) | — | (783 | ) | ||||||||||||||||||||||||||||||||||||||||||||
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Total net assets | $ | 5,194 | $ | 2,495 | $ | 1,689 | $ | 3,037 | $ | 12,415 | $ | 6,849 | $ | 2,495 | $ | 1,466 | $ | 3,037 | $ | 13,847 | $ | 6,016 | $ | 3,054 | $ | 1,308 | $ | 3,266 | $ | 13,644 | $ | 6,329 | $ | 3,027 | $ | 1,046 | $ | 3,266 | $ | 13,668 | ||||||||||||||||||||||||||||||||||||||||
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Generation | Exelon | Generation | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2015 | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2016 | 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) | $ | 104 | $ | — | $ | — | $ | — | $ | 104 | $ | 5,766 | $ | — | $ | — | $ | — | $ | 5,766 | $ | 39 | $ | — | $ | — | $ | — | $ | 39 | $ | 373 | $ | — | $ | — | $ | — | $ | 373 | ||||||||||||||||||||||||||||||||||||||||
NDT fund investments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents(b) | 219 | 92 | — | — | 311 | 219 | 92 | — | — | 311 | 110 | 19 | — | — | 129 | 110 | 19 | — | — | 129 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equities | 3,008 | — | — | 1,894 | 4,902 | 3,008 | — | — | 1,894 | 4,902 | 3,551 | 452 | — | 2,011 | 6,014 | 3,551 | 452 | — | 2,011 | 6,014 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Corporate debt | — | 1,824 | 242 | — | 2,066 | — | 1,824 | 242 | — | 2,066 | — | 1,554 | 250 | — | 1,804 | — | 1,554 | 250 | — | 1,804 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Treasury and agencies | 1,323 | 15 | — | — | 1,338 | 1,323 | 15 | — | — | 1,338 | 1,291 | 29 | — | — | 1,320 | 1,291 | 29 | — | — | 1,320 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Foreign governments | — | 61 | — | — | 61 | — | 61 | — | — | 61 | — | 37 | — | — | 37 | — | 37 | — | — | 37 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
State and municipal debt | — | 326 | — | — | 326 | — | 326 | — | — | 326 | — | 264 | — | — | 264 | — | 264 | — | — | 264 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other(c) | — | 147 | — | 390 | 537 | — | 147 | — | 390 | 537 | — | 59 | — | 493 | 552 | — | 59 | — | 493 | 552 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fixed income subtotal | 1,323 | 2,373 | 242 | 390 | 4,328 | 1,323 | 2,373 | 242 | 390 | 4,328 | 1,291 | 1,943 | 250 | 493 | 3,977 | 1,291 | 1,943 | 250 | 493 | 3,977 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Middle market lending | — | — | 428 | — | 428 | — | — | 428 | — | 428 | — | — | 427 | 71 | 498 | — | — | 427 | 71 | 498 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Private equity | — | — | — | 125 | 125 | — | — | — | 125 | 125 | — | — | — | 148 | 148 | — | — | — | 148 | 148 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Real estate | — | — | — | 35 | 35 | — | — | — | 35 | 35 | — | — | — | 326 | 326 | — | — | — | 326 | 326 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other | — | — | — | 216 | 216 | — | — | — | 216 | 216 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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NDT fund investments subtotal(d) | 4,550 | 2,465 | 670 | 2,660 | 10,345 | 4,550 | 2,465 | 670 | 2,660 | 10,345 | 4,952 | 2,414 | 677 | 3,049 | 11,092 | 4,952 | 2,414 | 677 | 3,049 | 11,092 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Pledged assets for Zion Station decommissioning | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | — | 17 | — | — | 17 | — | 17 | — | — | 17 | 11 | — | — | — | 11 | 11 | — | — | — | 11 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equities | 1 | 5 | — | — | 6 | 1 | 5 | — | — | 6 | — | 2 | — | — | 2 | — | 2 | — | — | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Treasury and agencies | 6 | 2 | — | — | 8 | 6 | 2 | — | — | 8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Corporate debt | — | 46 | — | — | 46 | — | 46 | — | — | 46 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other | — | 1 | — | — | 1 | — | 1 | — | — | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fixed income subtotal | 6 | 49 | — | — | 55 | 6 | 49 | — | — | 55 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fixed Income — U.S. Treasury and agencies | 16 | 1 | — | — | 17 | 16 | 1 | — | — | 17 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Middle market lending | — | — | 22 | 105 | 127 | — | — | 22 | 105 | 127 | — | — | 19 | 64 | 83 | — | — | 19 | 64 | 83 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Pledged assets for Zion Station decommissioning subtotal(e) | 7 | 71 | 22 | 105 | 205 | 7 | 71 | 22 | 105 | 205 | 27 | 3 | 19 | 64 | 113 | 27 | 3 | 19 | 64 | 113 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Rabbi trust investments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | 2 | — | — | — | 2 | 74 | — | — | — | 74 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mutual funds | 19 | — | — | — | 19 | 50 | — | — | — | 50 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fixed income | — | — | — | — | — | — | 16 | — | — | 16 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Life insurance contracts | — | 18 | — | — | 18 | — | 64 | 20 | — | 84 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Rabbi trust investments subtotal | 21 | 18 | — | — | 39 | 124 | 80 | 20 | — | 224 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation | Exelon | Generation | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2015 | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mutual funds | 17 | — | — | — | 17 | 48 | — | — | — | 48 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Life insurance contracts | — | 13 | — | — | 13 | — | 36 | — | — | 36 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Rabbi trust investments subtotal | 17 | 13 | — | — | 30 | 48 | 36 | — | — | 84 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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As of December 31, 2016 | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | Level 1 | Level 2 | Level 3 | Not subject to leveling | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivative assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | 1,922 | 3,467 | 1,707 | — | 7,096 | 1,922 | 3,467 | 1,707 | — | 7,096 | 1,356 | 2,505 | 1,229 | — | 5,090 | 1,358 | 2,505 | 1,229 | — | 5,092 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Proprietary trading | 36 | 64 | 30 | — | 130 | 36 | 64 | 30 | — | 130 | 3 | 50 | 23 | — | 76 | 3 | 50 | 23 | — | 76 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | (1,964 | ) | (2,629 | ) | (564 | ) | — | (5,157 | ) | (1,964 | ) | (2,629 | ) | (564 | ) | — | (5,157 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f)(g) | (1,162 | ) | (2,142 | ) | (481 | ) | — | (3,785 | ) | (1,164 | ) | (2,142 | ) | (481 | ) | — | (3,787 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Commodity derivative assets subtotal | (6 | ) | 902 | 1,173 | — | 2,069 | (6 | ) | 902 | 1,173 | — | 2,069 | 197 | 413 | 771 | — | 1,381 | 197 | 413 | 771 | — | 1,381 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Interest rate and foreign currency derivative assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives designated as hedging instruments | — | — | — | — | — | — | 25 | — | — | 25 | — | — | — | — | — | — | 16 | — | — | 16 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | — | 20 | — | — | 20 | — | 20 | — | — | 20 | — | 28 | — | — | 28 | — | 28 | — | — | 28 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Proprietary trading | 10 | 5 | — | — | 15 | 10 | 5 | — | — | 15 | 3 | 2 | — | — | 5 | 3 | 2 | — | — | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | (3 | ) | (3 | ) | — | — | (6 | ) | (3 | ) | (3 | ) | — | — | (6 | ) | (2 | ) | (19 | ) | — | — | (21 | ) | (2 | ) | (19 | ) | — | — | (21 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
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Interest rate and foreign currency derivative assets subtotal | 7 | 22 | — | — | 29 | 7 | 47 | — | — | 54 | 1 | 11 | — | — | 12 | 1 | 27 | — | — | 28 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Other investments | — | — | 33 | — | 33 | — | — | 33 | — | 33 | — | — | 42 | — | 42 | — | — | 42 | — | 42 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total assets | 4,679 | 3,473 | 1,898 | 2,765 | 12,815 | 10,372 | 3,521 | 1,898 | 2,765 | 18,556 | 5,237 | 2,859 | 1,509 | 3,113 | 12,718 | 5,674 | 2,937 | 1,529 | 3,113 | 13,253 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | (2,382 | ) | (3,348 | ) | (850 | ) | — | (6,580 | ) | (2,382 | ) | (3,348 | ) | (1,097 | ) | — | (6,827 | ) | (1,267 | ) | (2,378 | ) | (794 | ) | — | (4,439 | ) | (1,267 | ) | (2,378 | ) | (1,052 | ) | — | (4,697 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Proprietary trading | (33 | ) | (57 | ) | (37 | ) | — | (127 | ) | (33 | ) | (57 | ) | (37 | ) | — | (127 | ) | (3 | ) | (50 | ) | (26 | ) | — | (79 | ) | (3 | ) | (50 | ) | (26 | ) | — | (79 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | 2,440 | 3,186 | 765 | — | 6,391 | 2,440 | 3,186 | 765 | — | 6,391 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f)(g) | 1,233 | 2,339 | 542 | — | 4,114 | 1,233 | 2,339 | 542 | — | 4,114 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Commodity derivative liabilities subtotal | 25 | (219 | ) | (122 | ) | — | (316 | ) | 25 | (219 | ) | (369 | ) | — | (563 | ) | (37 | ) | (89 | ) | (278 | ) | — | (404 | ) | (37 | ) | (89 | ) | (536 | ) | — | (662 | ) | ||||||||||||||||||||||||||||||||||||||||||||||
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Interest rate and foreign currency derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives designated as hedging instruments | — | (16 | ) | — | — | (16 | ) | — | (16 | ) | — | — | (16 | ) | — | (10 | ) | — | — | (10 | ) | — | (10 | ) | — | — | (10 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | — | (3 | ) | — | — | (3 | ) | — | (3 | ) | — | — | (3 | ) | — | (21 | ) | — | — | (21 | ) | — | (21 | ) | — | — | (21 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Proprietary trading | (12 | ) | — | — | — | (12 | ) | (12 | ) | — | — | — | (12 | ) | (4 | ) | — | — | — | (4 | ) | (4 | ) | — | — | — | (4 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 12 | 3 | — | — | 15 | 12 | 3 | — | — | 15 | 4 | 19 | — | — | 23 | 4 | 19 | — | — | 23 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Interest rate and foreign currency derivative liabilities subtotal | — | (16 | ) | — | — | (16 | ) | — | (16 | ) | — | — | (16 | ) | — | (12 | ) | — | — | (12 | ) | — | (12 | ) | — | — | (12 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
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Deferred compensation obligation | — | (30 | ) | — | — | (30 | ) | — | (99 | ) | — | — | (99 | ) | — | (34 | ) | — | — | (34 | ) | — | (136 | ) | — | — | (136 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total liabilities | 25 | (265 | ) | (122 | ) | — | (362 | ) | 25 | (334 | ) | (369 | ) | — | (678 | ) | (37 | ) | (135 | ) | (278 | ) | — | (450 | ) | (37 | ) | (237 | ) | (536 | ) | — | (810 | ) | ||||||||||||||||||||||||||||||||||||||||||||||
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Total net assets | $ | 4,704 | $ | 3,208 | $ | 1,776 | $ | 2,765 | $ | 12,453 | $ | 10,397 | $ | 3,187 | $ | 1,529 | $ | 2,765 | $ | 17,878 | $ | 5,200 | $ | 2,724 | $ | 1,231 | $ | 3,113 | $ | 12,268 | $ | 5,637 | $ | 2,700 | $ | 993 | $ | 3,113 | $ | 12,443 | ||||||||||||||||||||||||||||||||||||||||
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(a) | Generation excludes cash of |
(b) | Includes |
(c) | Includes derivative instruments of |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(d) | Excludes net |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(e) | Excludes net assets of less than $1 million |
(f) | Collateral |
(g) | Of the collateral posted/(received), $14 million represents variation margin on the exchanges as of March 31, 2017. Of the collateral posted/(received), $(158) million represents variation margin on the exchanges as of December 31, 2016. |
ComEd, PECO and BGE
The following tables present assets and liabilities measured and recorded at fair value on ComEd’s, PECO’s and BGE’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2016March 31, 2017 and December 31, 2015:2016:
ComEd | PECO | BGE | ComEd | PECO | BGE | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of September 30, 2016 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2017 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | — | $ | — | $ | — | $ | — | $ | 521 | $ | — | $ | — | $ | 521 | $ | 375 | $ | — | $ | — | $ | 375 | $ | — | $ | — | $ | — | $ | — | $ | 5 | $ | — | $ | — | $ | 5 | $ | 45 | $ | — | $ | — | $ | 45 | ||||||||||||||||||||||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mutual funds | — | — | — | — | 7 | — | — | 7 | 4 | — | — | 4 | — | — | — | — | 7 | — | — | 7 | 5 | — | — | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Life insurance contracts | — | — | — | — | — | 11 | — | 11 | — | — | — | — | — | — | — | — | — | 10 | — | 10 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Rabbi trust investments subtotal | — | — | — | — | 7 | 11 | — | 18 | 4 | — | — | 4 | — | — | — | — | 7 | 10 | — | 17 | 5 | — | — | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total assets | — | — | — | — | 528 | 11 | — | 539 | 379 | — | — | 379 | — | — | — | — | 12 | 10 | — | 22 | 50 | — | — | 50 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (8 | ) | — | (8 | ) | — | (10 | ) | — | (10 | ) | — | (4 | ) | — | (4 | ) | — | (8 | ) | — | (8 | ) | — | (11 | ) | — | (11 | ) | — | (4 | ) | — | (4 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities(b) | — | — | (244 | ) | (244 | ) | — | — | — | — | — | — | — | — | — | — | (282 | ) | (282 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total liabilities | — | (8 | ) | (244 | ) | (252 | ) | — | (10 | ) | — | (10 | ) | — | (4 | ) | — | (4 | ) | — | (8 | ) | (282 | ) | (290 | ) | — | (11 | ) | — | (11 | ) | — | (4 | ) | — | (4 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total net assets (liabilities) | $ | — | $ | (8 | ) | $ | (244 | ) | $ | (252 | ) | $ | 528 | $ | 1 | $ | — | $ | 529 | $ | 379 | $ | (4 | ) | $ | — | $ | 375 | $ | — | $ | (8 | ) | $ | (282 | ) | $ | (290 | ) | $ | 12 | $ | (1 | ) | $ | — | $ | 11 | $ | 50 | $ | (4 | ) | $ | — | $ | 46 | |||||||||||||||||||||||||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
ComEd | PECO | BGE | ComEd | PECO | BGE | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2015 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2016 | 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) | $ | 29 | $ | — | $ | — | $ | 29 | $ | 271 | $ | — | $ | — | $ | 271 | $ | 25 | $ | — | $ | — | $ | 25 | $ | 20 | $ | — | $ | — | $ | 20 | $ | 45 | $ | — | $ | — | $ | 45 | $ | 36 | $ | — | $ | — | $ | 36 | ||||||||||||||||||||||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mutual funds | — | — | — | — | 8 | — | — | 8 | 4 | — | — | 4 | — | — | — | — | 7 | — | — | 7 | 4 | — | — | 4 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Life insurance contracts | — | — | — | — | — | 12 | — | 12 | — | — | — | — | — | — | — | — | — | 10 | — | 10 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Rabbi trust investments subtotal | — | — | — | — | 8 | 12 | — | 20 | 4 | — | — | 4 | — | — | — | — | 7 | 10 | — | 17 | 4 | — | — | 4 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total assets | 29 | — | — | 29 | 279 | 12 | — | 291 | 29 | — | — | 29 | 20 | — | — | 20 | 52 | 10 | — | 62 | 40 | — | — | 40 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (8 | ) | — | (8 | ) | — | (12 | ) | — | (12 | ) | — | (4 | ) | — | (4 | ) | — | (8 | ) | — | (8 | ) | — | (11 | ) | — | (11 | ) | — | (4 | ) | — | (4 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities(b) | — | — | (247 | ) | (247 | ) | — | — | — | — | — | — | — | — | — | — | (258 | ) | (258 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total liabilities | — | (8 | ) | (247 | ) | (255 | ) | — | (12 | ) | — | (12 | ) | — | (4 | ) | — | (4 | ) | — | (8 | ) | (258 | ) | (266 | ) | — | (11 | ) | — | (11 | ) | — | (4 | ) | — | (4 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total net assets (liabilities) | $ | 29 | $ | (8 | ) | $ | (247 | ) | $ | (226 | ) | $ | 279 | $ | — | $ | — | $ | 279 | $ | 29 | $ | (4 | ) | $ | — | $ | 25 | $ | 20 | $ | (8 | ) | $ | (258 | ) | $ | (246 | ) | $ | 52 | $ | (1 | ) | $ | — | $ | 51 | $ | 40 | $ | (4 | ) | $ | — | $ | 36 | |||||||||||||||||||||||||||||||||||||||
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(a) | ComEd excludes cash of |
(b) | The Level 3 balance consists of the current and noncurrent liability of $19 million and |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
PHI, Pepco, DPL and ACE
The following tables present assets and liabilities measured and recorded at fair value on PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2016March 31, 2017 and December 31, 2015:2016:
Successor | Predecessor | Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of September 30, 2016 | As of December 31, 2015 | As of March 31, 2017 | As of December 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PHI | Level 1 | Level 2 | Level 3 | Total | 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) | $ | 347 | $ | — | $ | — | $ | 347 | $ | 42 | $ | — | $ | — | $ | 42 | $ | 154 | $ | — | $ | — | $ | 154 | $ | 217 | $ | — | $ | — | $ | 217 | ||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets | 1 | — | — | 1 | — | — | 18 | 18 | — | — | — | — | 2 | — | — | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | (1 | ) | — | — | (1 | ) | — | — | — | — | — | — | — | — | (2 | ) | — | — | (2 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
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Mark-to-market derivative assets subtotal | — | — | — | — | — | — | 18 | 18 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
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Rabbi trust investments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | 73 | — | — | 73 | 12 | — | — | 12 | 74 | — | — | 74 | 73 | — | — | 73 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Fixed income | — | 14 | — | 14 | — | 15 | — | 15 | — | 15 | — | 15 | — | 16 | — | 16 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Life insurance contracts | — | 22 | 21 | 43 | — | 27 | 19 | 46 | — | 23 | 20 | 43 | — | 22 | 20 | 42 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
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Rabbi trust investments subtotal | 73 | 36 | 21 | 130 | 12 | 42 | 19 | 73 | 74 | 38 | 20 | 132 | 73 | 38 | 20 | 131 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total assets | 420 | 36 | 21 | 477 | 54 | 42 | 37 | 133 | 228 | 38 | 20 | 286 | 290 | 38 | 20 | 348 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
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Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (28 | ) | — | (28 | ) | — | (30 | ) | — | (30 | ) | — | (25 | ) | — | (25 | ) | — | (28 | ) | — | (28 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities(b) | — | — | — | — | (2 | ) | — | — | (2 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | — | — | — | — | 2 | — | — | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mark-to-market derivative liabilities subtotal | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total liabilities | — | (28 | ) | — | (28 | ) | — | (30 | ) | — | (30 | ) | — | (25 | ) | — | (25 | ) | — | (28 | ) | — | (28 | ) | ||||||||||||||||||||||||||||||||||||||||||||
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Total net assets | $ | 420 | $ | 8 | $ | 21 | $ | 449 | $ | 54 | $ | 12 | $ | 37 | $ | 103 | $ | 228 | $ | 13 | $ | 20 | $ | 261 | $ | 290 | $ | 10 | $ | 20 | $ | 320 | ||||||||||||||||||||||||||||||||||||
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Pepco | DPL | ACE | ||||||||||||||||||||||||||||||||||||||||||||||
As of March 31, 2017 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | 33 | $ | — | $ | — | $ | 33 | $ | 39 | $ | — | $ | — | $ | 39 | $ | 80 | $ | — | $ | — | $ | 80 | ||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | 43 | — | — | 43 | 1 | — | — | 1 | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Fixed income | — | 15 | — | 15 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Life insurance contracts | — | 23 | 20 | 43 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
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Rabbi trust investments subtotal | 43 | 38 | 20 | 101 | 1 | — | — | 1 | — | — | — | — | ||||||||||||||||||||||||||||||||||||
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Total assets | 76 | 38 | 20 | 134 | 40 | — | — | 40 | 80 | — | — | 80 | ||||||||||||||||||||||||||||||||||||
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Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (4 | ) | — | (4 | ) | — | (1 | ) | — | (1 | ) | — | — | — | — | ||||||||||||||||||||||||||||||||
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Total liabilities | — | (4 | ) | — | (4 | ) | — | (1 | ) | — | (1 | ) | — | — | — | — | ||||||||||||||||||||||||||||||||
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| |||||||||||||||||||||||||
Total net assets (liabilities) | $ | 76 | $ | 34 | $ | 20 | $ | 130 | $ | 40 | $ | (1 | ) | $ | — | $ | 39 | $ | 80 | $ | — | $ | — | $ | 80 | |||||||||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Pepco | DPL | ACE | Pepco | DPL | ACE | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of September 30, 2016 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2016 | 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) | $ | 127 | $ | — | $ | — | $ | 127 | $ | — | $ | — | $ | — | $ | — | $ | 194 | $ | — | $ | — | $ | 194 | $ | 33 | $ | — | $ | — | $ | 33 | $ | 42 | $ | — | $ | — | $ | 42 | $ | 130 | $ | — | $ | — | $ | 130 | ||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets(b) | — | — | — | — | 1 | — | — | 1 | — | — | — | — | — | — | — | — | 2 | — | — | 2 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | — | — | — | — | (1 | ) | — | — | (1 | ) | — | — | — | — | — | — | — | — | (2 | ) | — | — | (2 | ) | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mark-to-market derivative assets subtotal | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Rabbi trust investments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | 43 | — | — | 43 | — | — | — | — | — | — | — | — | 43 | — | — | 43 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fixed income | — | 14 | — | 14 | — | — | — | — | — | — | — | — | — | 16 | — | 16 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Life insurance contracts | — | 22 | 21 | 43 | — | — | — | — | — | — | — | — | — | 22 | 19 | 41 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Rabbi trust investments subtotal | 43 | 36 | 21 | 100 | — | — | — | — | — | — | — | — | 43 | 38 | 19 | 100 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total assets | 170 | 36 | 21 | 227 | — | — | — | — | 194 | — | — | 194 | 76 | 38 | 19 | 133 | 42 | — | — | 42 | 130 | — | — | 130 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (5 | ) | — | (5 | ) | — | (1 | ) | — | (1 | ) | — | — | — | — | — | (5 | ) | — | (5 | ) | — | (1 | ) | — | (1 | ) | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total liabilities | — | (5 | ) | — | (5 | ) | — | (1 | ) | — | (1 | ) | — | — | — | — | — | (5 | ) | — | (5 | ) | — | (1 | ) | — | (1 | ) | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total net assets (liabilities) | $ | 170 | $ | 31 | $ | 21 | $ | 222 | $ | — | $ | (1 | ) | $ | — | $ | (1 | ) | $ | 194 | $ | — | $ | — | $ | 194 | $ | 76 | $ | 33 | $ | 19 | $ | 128 | $ | 42 | $ | (1 | ) | $ | — | $ | 41 | $ | 130 | $ | — | $ | — | $ | 130 | |||||||||||||||||||||||||||||||||||||||||||||
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Pepco | DPL | ACE | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2015 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 2 | $ | — | $ | — | $ | 2 | $ | — | $ | — | $ | — | $ | — | $ | 30 | $ | — | $ | — | $ | 30 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | 11 | — | — | 11 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fixed income | — | 15 | — | 15 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Life insurance contracts | — | 23 | 19 | 42 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Rabbi trust investments subtotal | 11 | 38 | 19 | 68 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total assets | 13 | 38 | 19 | 70 | — | — | — | — | 30 | — | — | 30 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (6 | ) | — | (6 | ) | — | (1 | ) | — | (1 | ) | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities(b) | — | — | — | — | (2 | ) | — | — | (2 | ) | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | — | — | — | — | 2 | — | — | 2 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mark-to-market derivative liabilities subtotal | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total liabilities | — | (6 | ) | — | (6 | ) | — | (1 | ) | — | (1 | ) | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total net assets (liabilities) | $ | 13 | $ | 32 | $ | 19 | $ | 64 | $ | — | $ | (1 | ) | $ | — | $ | (1 | ) | $ | 30 | $ | — | $ | — | $ | 30 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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(a) | PHI excludes cash of |
(b) | Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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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, 2016March 31, 2017 and 2015:2016:
Successor | ||||||||||||||||||||||||||||||||||||
Generation | ComEd | PHI | Exelon | |||||||||||||||||||||||||||||||||
Three Months Ended | NDT Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to- Market Derivatives | Other Investments | Total Generation | Mark-to- Market Derivatives(a) | Life Insurance Contracts | Eliminated in Consolidation | Total | |||||||||||||||||||||||||||
Balance as of June 30, 2016 | $ | 715 | $ | 25 | $ | 609 | $ | 37 | $ | 1,386 | $ | (221 | ) | $ | 20 | $ | — | $ | 1,185 | |||||||||||||||||
Total realized / unrealized gains (losses) | ||||||||||||||||||||||||||||||||||||
Included in net income | (4 | ) | — | 95 | (b) | 1 | 92 | — | 1 | — | 93 | |||||||||||||||||||||||||
Included in noncurrent payables to affiliates | 6 | — | — | — | 6 | — | — | (6 | ) | — | ||||||||||||||||||||||||||
Included in payable for Zion Station decommissioning | — | (1 | ) | — | — | (1 | ) | — | — | — | (1 | ) | ||||||||||||||||||||||||
Included in regulatory assets | — | — | — | — | — | (23 | ) | — | 6 | (17 | ) | |||||||||||||||||||||||||
Change in collateral | — | — | 31 | — | 31 | — | — | — | 31 | |||||||||||||||||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||||||||||||||||||
Purchases | 4 | — | 207 | (d) | 3 | 214 | — | — | — | 214 | ||||||||||||||||||||||||||
Sales | — | (5 | ) | (2 | ) | — | (7 | ) | — | — | — | (7 | ) | |||||||||||||||||||||||
Issuances | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Settlements | (28 | ) | — | — | — | (28 | ) | — | — | — | (28 | ) | ||||||||||||||||||||||||
Transfers into Level 3 | — | — | (1 | ) | 1 | — | — | — | — | — | ||||||||||||||||||||||||||
Transfers out of Level 3 | — | — | (4 | ) | — | (4 | ) | — | — | — | (4 | ) | ||||||||||||||||||||||||
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Balance at September 30, 2016 | $ | 693 | $ | 19 | $ | 935 | $ | 42 | $ | 1,689 | $ | (244 | ) | $ | 21 | $ | — | $ | 1,466 | |||||||||||||||||
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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, 2016 | $ | 3 | $ | — | $ | 285 | $ | — | $ | 288 | $ | — | $ | — | $ | — | $ | 288 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Generation | ComEd | PHI(c) | Exelon | Generation | ComEd | PHI | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2016 | NDT Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to- Market Derivatives | Other Investments | Total Generation | Mark-to- Market Derivatives(a) | Life Insurance Contracts | Eliminated in Consolidation | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance as of December 31, 2015 | $ | 670 | $ | 22 | $ | 1,051 | $ | 33 | $ | 1,776 | $ | (247 | ) | $ | — | $ | — | $ | 1,529 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Included due to merger | — | — | — | — | — | — | 20 | — | 20 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Three Months Ended | NDT Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to- Market Derivatives | Other Investments | Total Generation | Mark-to- Market Derivatives(a) | Life Insurance Contracts | Eliminated in Consolidation | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance as of December 31, 2016 | $ | 677 | $ | 19 | $ | 493 | $ | 42 | $ | 1,231 | $ | (258 | ) | $ | 20 | $ | — | $ | 993 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Total realized / unrealized gains (losses) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Included in net income | 2 | — | (339 | )(b) | 1 | (336 | ) | — | 2 | — | (334 | ) | 3 | — | (43 | )(b) | 1 | (39 | ) | — | 1 | — | (38 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
Included in noncurrent payables to affiliates | 18 | — | — | — | 18 | — | — | (18 | ) | — | 9 | — | — | — | 9 | — | — | (9 | ) | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Included in payable for Zion Station decommissioning | — | 1 | — | — | 1 | — | — | — | 1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Included in regulatory assets/liabilities | — | — | — | — | — | 3 | — | 18 | 21 | — | — | — | — | — | (24 | ) | — | 9 | (15 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Change in collateral | — | — | (51 | ) | — | (51 | ) | — | — | — | (51 | ) | — | — | 38 | — | 38 | — | — | — | 38 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchases | 123 | 1 | 289 | (d) | 7 | 420 | — | — | — | 420 | 17 | 1 | 69 | 2 | 89 | — | — | — | 89 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Sales | (1 | ) | (5 | ) | (5 | ) | — | (11 | ) | — | — | — | (11 | ) | — | — | (2 | ) | — | (2 | ) | — | — | — | (2 | ) | ||||||||||||||||||||||||||||||||||||||||||||||
Issuances | — | — | — | — | — | — | (1 | ) | — | (1 | ) | — | — | — | — | — | — | (1 | ) | — | (1 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||
Settlements | (119 | ) | — | — | — | (119 | ) | — | — | — | (119 | ) | (23 | ) | — | — | — | (23 | ) | — | — | — | (23 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
Transfers into Level 3 | — | — | 1 | 1 | 2 | — | — | — | 2 | — | — | (1 | ) | — | (1 | ) | — | — | — | (1 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||
Transfers out of Level 3 | — | — | (11 | ) | — | (11 | ) | — | — | — | (11 | ) | — | — | 11 | (5 | ) | 6 | — | — | — | 6 | ||||||||||||||||||||||||||||||||||||||||||||||||||
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Balance as of September 30, 2016 | $ | 693 | $ | 19 | $ | 935 | $ | 42 | $ | 1,689 | $ | (244 | ) | $ | 21 | $ | — | $ | 1,466 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance as of March 31, 2017 | $ | 683 | $ | 20 | $ | 565 | $ | 40 | $ | 1,308 | $ | (282 | ) | $ | 20 | $ | — | $ | 1,046 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
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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, 2016 | $ | 7 | $ | — | $ | 240 | $ | — | $ | 247 | $ | — | $ | 1 | $ | — | $ | 248 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2017 | $ | 2 | $ | — | $ | 59 | $ | — | $ | 61 | $ | — | $ | 1 | $ | — | $ | 62 |
(a) | Includes |
(b) | Includes a reduction for the reclassification of |
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation | ComEd | Exelon | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, 2015 | NDT Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to- Market Derivatives | Other Investments | Total Generation | Mark-to- Market Derivatives(a) | Eliminated in Consolidation | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance as of June 30, 2015 | $ | 667 | $ | 41 | $ | 1,021 | $ | 30 | $ | 1,759 | $ | (223 | ) | $ | — | $ | 1,536 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Generation | ComEd | PHI(c) | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Three Months Ended | NDT Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to- Market Derivatives | Other Investments | Total Generation | Mark-to- Market Derivatives(a) | Life Insurance Contracts | Eliminated in Consolidation | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance as of December 31, 2015 | $ | 670 | $ | 22 | $ | 1,051 | $ | 33 | $ | 1,776 | $ | (247 | ) | $ | — | $ | — | $ | 1,529 | |||||||||||||||||||||||||||||||||||||||||||||||||
Included due to merger | — | — | — | — | — | — | 20 | — | 20 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total realized / unrealized gains (losses) | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Included in net income | — | — | (48 | )(b) | — | (48 | ) | — | — | (48 | ) | 2 | — | (6 | )(b) | — | (4 | ) | — | — | — | (4 | ) | |||||||||||||||||||||||||||||||||||||||||||||
Included in noncurrent payables to affiliates | — | — | — | — | — | — | — | — | 4 | — | — | — | 4 | — | — | (4 | ) | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
Included in payable for Zion Station decommissioning | — | 1 | — | — | 1 | — | — | 1 | — | 2 | — | — | 2 | — | — | — | 2 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Included in regulatory assets | — | — | — | — | — | (20 | ) | — | (20 | ) | — | — | — | — | — | (18 | ) | — | 4 | (14 | ) | |||||||||||||||||||||||||||||||||||||||||||||||
Change in collateral | — | — | 90 | — | 90 | — | — | 90 | — | — | (50 | ) | — | (50 | ) | — | — | — | (50 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchases | 15 | — | 50 | 2 | 67 | — | — | 67 | 34 | 1 | 59 | 3 | 97 | — | — | — | 97 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Sales | — | (13 | ) | (5 | ) | — | (18 | ) | — | — | (18 | ) | — | — | (2 | ) | — | (2 | ) | — | — | — | (2 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Settlements | (13 | ) | — | — | — | (13 | ) | — | — | (13 | ) | (26 | ) | — | — | — | (26 | ) | — | — | — | (26 | ) | |||||||||||||||||||||||||||||||||||||||||||||
Transfers into Level 3 | — | — | 69 | — | 69 | — | — | 69 | — | — | 2 | — | 2 | — | — | — | 2 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Transfers out of Level 3 | — | — | (3 | ) | — | (3 | ) | — | — | (3 | ) | — | — | (7 | ) | — | (7 | ) | — | — | — | (7 | ) | |||||||||||||||||||||||||||||||||||||||||||||
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Balance as of September 30, 2015 | $ | 669 | $ | 29 | $ | 1,174 | $ | 32 | $ | 1,904 | $ | (243 | ) | $ | — | $ | 1,661 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Balance as of March 31, 2016 | $ | 684 | $ | 25 | $ | 1,047 | $ | 36 | $ | 1,792 | $ | (265 | ) | $ | 20 | $ | — | $ | 1,547 | |||||||||||||||||||||||||||||||||||||||||||||||||
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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, 2015 | $ | (1 | ) | $ | — | $ | 181 | $ | — | $ | 180 | $ | — | $ | — | $ | 180 | |||||||||||||||||||||||||||||||||||||||||||||||||||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2016 | $ | 1 | $ | — | $ | 219 | $ | — | $ | 220 | $ | — | $ | — | $ | — | $ | 220 |
(a) | Includes $25 million of decreases in fair value and an increase for realized losses due to settlements of $7 million recorded in purchased power expense associated withfloating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2016. |
(b) | Includes a reduction for the reclassification of $225 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three months ended March 31, 2016. |
(c) | Successor period represents activity from March 24, 2016 through March 31, 2016. See tables below for PHI’s predecessor periods, as well as activity for Pepco for the three months ended March 31, 2017 and 2016. |
Predecessor | ||||||||
January 1, 2016 to March 23, 2016 | ||||||||
PHI | Preferred Stock | Life Insurance Contracts | ||||||
Beginning Balance | $ | 18 | $ | 19 | ||||
Total realized / unrealized gains (losses) | ||||||||
Included in net income | (18 | ) | 1 | |||||
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Ending Balance | $ | — | $ | 20 | ||||
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The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period | $ | — | $ | 1 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation | ComEd | Exelon | ||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2015 | NDT Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to- Market Derivatives | Other Investments | Total Generation | Mark-to- Market Derivatives(a) | Eliminated in Consolidation | Total | ||||||||||||||||||||||||
Balance as of December 31, 2014 | $ | 605 | $ | 50 | $ | 1,050 | $ | 3 | $ | 1,708 | $ | (207 | ) | $ | — | $ | 1,501 | |||||||||||||||
Total realized / unrealized gains (losses) | ||||||||||||||||||||||||||||||||
Included in net income | 4 | — | (87 | )(b) | — | (83 | ) | — | — | (83 | ) | |||||||||||||||||||||
Included in noncurrent payables to affiliates | 17 | — | — | — | 17 | — | (17 | ) | — | |||||||||||||||||||||||
Included in payable for Zion Station decommissioning | — | 2 | — | — | 2 | — | — | 2 | ||||||||||||||||||||||||
Included in regulatory assets | — | — | — | — | — | (36 | ) | 17 | (19 | ) | ||||||||||||||||||||||
Change in collateral | — | — | 72 | — | 72 | — | — | 72 | ||||||||||||||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||||||||||||||
Purchases | 122 | 1 | 107 | 29 | 259 | — | — | 259 | ||||||||||||||||||||||||
Sales | (8 | ) | (24 | ) | (10 | ) | — | (42 | ) | — | — | (42 | ) | |||||||||||||||||||
Settlements | (75 | ) | — | — | — | (75 | ) | — | — | (75 | ) | |||||||||||||||||||||
Transfers into Level 3 | 4 | — | 80 | — | 84 | — | — | 84 | ||||||||||||||||||||||||
Transfers out of Level 3 | — | — | (38 | ) | — | (38 | ) | — | — | (38 | ) | |||||||||||||||||||||
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Balance as of September 30, 2015 | $ | 669 | $ | 29 | $ | 1,174 | $ | 32 | $ | 1,904 | $ | (243 | ) | $ | — | $ | 1,661 | |||||||||||||||
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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, 2015 | $ | 2 | $ | — | $ | 536 | $ | — | $ | 538 | $ | — | $ | — | $ | 538 |
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Successor | Predecessor | |||||||||||||||
Three Months Ended September 30, 2016 | Three Months Ended September 30, 2015 | |||||||||||||||
PHI | Life Insurance Contracts | Preferred Stock | Life Insurance Contracts | |||||||||||||
Beginning Balance | $ | 20 | $ | 3 | $ | 20 | ||||||||||
Total realized / unrealized gains (losses) | ||||||||||||||||
Included in net income | 1 | 15 | 1 | |||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||
Issuances | — | — | (2 | ) | ||||||||||||
Settlements | — | — | — | |||||||||||||
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Ending Balance | $ | 21 | $ | 18 | $ | 19 | ||||||||||
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The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period | $ | — | $ | 15 | $ | — |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Successor | Predecessor | Predecessor | ||||||||||||||||||||||
March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | Nine Months Ended September 30, 2015 | ||||||||||||||||||||||
PHI | Life Insurance Contracts | Preferred Stock | Life Insurance Contracts | Preferred Stock | Life Insurance Contracts | |||||||||||||||||||
Beginning Balance | $ | 20 | $ | 18 | $ | 19 | $ | 3 | $ | 19 | ||||||||||||||
Total realized / unrealized gains (losses) | ||||||||||||||||||||||||
Included in net income | 2 | (18 | ) | 1 | 15 | 4 | ||||||||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||||||
Issuances | (1 | ) | — | — | — | (3 | ) | |||||||||||||||||
Settlements | — | — | — | — | (1 | ) | ||||||||||||||||||
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Ending Balance | $ | 21 | $ | — | $ | 20 | $ | 18 | $ | 19 | ||||||||||||||
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The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period | $ | 1 | $ | — | $ | 1 | $ | 15 | $ | 2 |
Three Months Ended September 30, 2016 | Three Months Ended September 30, 2015 | |||||||
Pepco | Pepco | |||||||
Life Insurance Contracts | Life Insurance Contracts | |||||||
Beginning Balance | $ | 20 | $ | 20 | ||||
Total realized / unrealized gains (losses) | ||||||||
Included in net income | 1 | 1 | ||||||
Purchases, sales, issuances and settlements | ||||||||
Issuances | — | (3 | ) | |||||
Settlements | — | — | ||||||
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Ending Balance | $ | 21 | $ | 18 | ||||
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The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period | $ | — | | $ | — | |
Nine Months Ended September 30, 2016 | Nine Months Ended September 30, 2015 | |||||||||||
Pepco | Pepco | DPL | ||||||||||
Life Insurance Contracts | Life Insurance Contracts | Life Insurance Contracts | ||||||||||
Beginning Balance | $ | 19 | $ | 18 | $ | 1 | ||||||
Total realized / unrealized gains (losses) | ||||||||||||
Included in net income | 3 | 4 | — | |||||||||
Purchases, sales, issuances and settlements | ||||||||||||
Issuances | (1 | ) | (4 | ) | — | |||||||
Settlements | — | — | (1 | ) | ||||||||
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Ending Balance | $ | 21 | $ | 18 | $ | — | ||||||
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The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period | $ | 2 | $ | 2 | $ | — |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Life Insurance Contracts Three Months Ended March 31, | ||||||||
Pepco | 2017 | 2016 | ||||||
Beginning Balance | $ | 20 | $ | 19 | ||||
Total realized / unrealized gains (losses) | ||||||||
Included in net income | 1 | 1 | ||||||
Purchases, sales, issuances and settlements | ||||||||
Issuances | (1 | ) | — | |||||
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Ending Balance | $ | 20 | $ | 20 | ||||
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The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period | $ | 1 | $ | 1 |
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, 2016March 31, 2017 and 2015:2016:
Generation | Exelon | |||||||||||||||||||||||
Operating Revenues | Purchased Power and Fuel | Other, net(a) | Operating Revenues | Purchased Power and Fuel | Other, net(a) | |||||||||||||||||||
Total gains (losses) included in net income for the three months ended September 30, 2016 | $ | 180 | $ | (85 | ) | $ | (4 | ) | $ | 180 | $ | (85 | ) | $ | (3 | ) | ||||||||
Total gains (losses) included in net income for the nine months ended September 30, 2016 | (232 | ) | (107 | ) | 2 | (232 | ) | (107 | ) | 4 | ||||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2016 | 323 | (38 | ) | 3 | 323 | (38 | ) | 3 | ||||||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2016 | 303 | (63 | ) | 7 | 303 | (63 | ) | 8 |
Successor | ||||||||||||||||||||||||||||
Generation | PHI | Exelon | ||||||||||||||||||||||||||
Operating Revenues | Purchased Power and Fuel | Other, net(a) | Other, net(a) | Operating Revenues | Purchased Power and Fuel | Other, net(a) | ||||||||||||||||||||||
Total gains (losses) included in net income for the three months ended March 31, 2017 | 88 | (131 | ) | 3 | 1 | 88 | (131 | ) | 4 | |||||||||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2017 | 140 | (81 | ) | 2 | 1 | 140 | (81 | ) | 3 |
Generation | Exelon | |||||||||||||||||||||||
Operating Revenues | Purchased Power and Fuel | Other, net(a) | Operating Revenues | Purchased Power and Fuel | Other, net(a) | |||||||||||||||||||
Total gains (losses) included in net income for the three months ended September 30, 2015 | $ | (4 | ) | $ | (44 | ) | $ | — | $ | (4 | ) | $ | (44 | ) | $ | — | ||||||||
Total gains (losses) included in net income for the nine months ended September 30, 2015 | (31 | ) | (56 | ) | 4 | (31 | ) | (56 | ) | 4 | ||||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2015 | 198 | (17 | ) | (1 | ) | 198 | (17 | ) | (1 | ) | ||||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2015 | 538 | (2 | ) | 2 | 538 | (2 | ) | 2 |
Generation | Exelon | |||||||||||||||||||||||
Operating Revenues | Purchased Power and Fuel | Other, net(a) | Operating Revenues | Purchased Power and Fuel | Other, net(a) | |||||||||||||||||||
Total gains (losses) included in net income for the three months ended March 31, 2016 | 49 | (55 | ) | 2 | 49 | (55 | ) | 2 | ||||||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2016 | 254 | (35 | ) | 1 | 254 | (35 | ) | 1 |
Successor | Predecessor | |||||||||||||||||||
PHI | PHI | Pepco | ||||||||||||||||||
Three Months Ended September 30, 2016 | Three Months Ended September 30, 2015 | Three Months Ended September 30, 2016 | Three Months Ended September 30, 2015 | |||||||||||||||||
Other, net | Other, net | Other, net | ||||||||||||||||||
Total gains (losses) included in net income | $ | 1 | $ | 16 | $ | 1 | $ | 1 | ||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held | — | 15 | — | — |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Successor | Predecessor | Predecessor | ||||||||||||||||||||||||||||||||||
PHI | PHI | Pepco | PHI | Pepco | ||||||||||||||||||||||||||||||||
March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | Nine Months Ended September 30, 2015 | Nine Months Ended September 30, 2016 | Nine Months Ended September 30, 2015 | January 1, 2016 to March 23, 2016 | Three Months Ended March 31, 2017 | Three Months Ended March 31, 2016 | |||||||||||||||||||||||||||||
Other, net | Other, net | Other, net | Other, net | |||||||||||||||||||||||||||||||||
Total gains (losses) included in net income | $ | 2 | $ | (17 | ) | $ | 19 | $ | 3 | $ | 4 | |||||||||||||||||||||||||
Total gains (losses)included in net income | $ | (17 | ) | $ | 1 | $ | 1 | |||||||||||||||||||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held | 1 | 1 | 17 | 2 | 2 | 1 | 1 | 1 |
(a) | Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation and the life insurance contracts held by PHI and Pepco. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Valuation Techniques Used to Determine Fair Value
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.
Cash Equivalents (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). The Registrants’ cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.
Preferred Stock Derivative (PHI). In connection with entering into the PHI Merger Agreement, as further described in Note 16 — Mezzanine Equity, PHI entered into a Subscription Agreement with Exelon dated April 29, 2014, pursuant to which PHI issued to Exelon shares of Preferred stock. The Preferred stock contained embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding Preferred stock could be called and redeemed at a nominal par value upon a termination of the merger agreement under certain circumstances due to the failure to obtain required regulatory approvals. The embedded call and redemption features on the shares of the Preferred stock in the event of such a termination were separately accounted for as derivatives. These Preferred stock derivatives were valued quarterly using quantitative and qualitative factors, including management’s assessment of the likelihood of a Regulatory Termination and therefore, were categorized in Level 3 in the fair value hierarchy. As a result of the PHI Merger, the PHI Preferred stock derivative was reduced to zero as of March 23, 2016. Thewrite-off was charged to Other, net on the PHI Consolidated Statement of Operations and Comprehensive Income.
Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation).The trust fund investments have been established to satisfy Generation’s and CENG’s nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in Equities and Fixed Income and Other.Income. Generation’s and CENG’s NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds which are based on quoted prices in active markets are categorized in Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.
For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixed income securities, which are included in Corporate debt, are determined using a third party valuation that contains significant unobservable inputs and are categorized in Level 3.
Equity and fixed income commingled funds and mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives such as holding short term fixed income securities or tracking the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For commingled funds and mutual funds, which are not publicly quoted, the funds are valued using NAV as a practical expedient for fair value, which is primarily derived from the quoted prices in active markets on the underlying securities, and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.
Derivative instruments consisting primarily of futures and interest rate swaps to manage risk are recorded at fair value. Over the counter derivatives are valued daily based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over the counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.
Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models and income models. Investments in loans are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Managed funds are valued using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.
Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. The fair value of private equity and real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date. 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 not highly observable.unobservable.
As of September 30, 2016,March 31, 2017, Generation has outstanding commitments to invest in middle market lending, private equity investments and real estate investments of approximately $170$290 million, $73$120 million, and $220$107 million, respectively. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Concentrations of Credit Risk. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of September 30, 2016.March 31, 2017. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of September 30, 2016,March 31, 2017, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation’s NDT assets.
See Note 12 — Nuclear Decommissioning for further discussion on the NDT fund investments.
Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities and life insurance policies. The mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3.
Mark-to-Market Derivatives (Exelon, Generation, ComEd, PHI and DPL).Derivative contracts are traded in both exchange-based andnon-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers orover-the-counter,on-line exchanges and are categorized in Level 2. These price quotations reflect the average of thebid-ask,mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points,bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominately at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.
Exelon may utilizefixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market’s expectation of future interest rates. Additional inputs to the net present value
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 9 — 9—Derivative Financial Instruments for further discussion onmark-to-market derivatives.
Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.
The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.
Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd, PHI, Pepco and DPL)
Mark-to-Market Derivatives (Exelon, Generation and ComEd).For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. 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. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements.
Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.81$2.67 and $0.36$0.40 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See ITEM 3. —QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for information regarding the maturity by year of the Registrants’ mark-to-market derivative assets and liabilities.
On December 17, 2010, ComEd entered into several20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 9 —Derivative— Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.
The table below discloses the significant inputs to the forward curve used to value these positions.
Type of trade | Fair Value at March 31, 2017 | Valuation Technique | Unobservable Input | Range | ||||||
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(c) | $ | 464 | Discounted Cash Flow | Forward power price | $8 — $130 | |||||
Forward gas price | $1.92 — $9.87 | |||||||||
Option Model | Volatility percentage | 13% — 112% | ||||||||
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(c) | $ | 3 | Discounted Cash Flow | Forward power price | $15 — $67 | |||||
Mark-to-market derivatives (Exelon and ComEd) | $ | (282 | ) | Discounted Cash Flow | Forward heat rate(b) | 8x — 9x | ||||
Marketability reserve | 3% — 8% | |||||||||
Renewable factor | 88% — 121% |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The table below discloses the significant inputs to the forward curve used to value these positions.
Type of trade | Fair Value at September 30, 2016 | Valuation Technique | Unobservable Input | Range | ||||||
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(c) | $ | 788 | Discounted Cash Flow | Forward power price | $6 — $130 | |||||
Forward gas price | $1.24 — $9.53 | |||||||||
Option Model | Volatility percentage | 5% — 115% | ||||||||
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(c) | $ | (3 | ) | Discounted Cash Flow | Forward power price | $15 — $68 | ||||
Mark-to-market derivatives (Exelon and ComEd) | $ | (244 | ) | Discounted Cash Flow | Forward heat rate(b) | 8x — 9x | ||||
Marketability reserve | 3% — 8% | |||||||||
Renewable factor | 86% — 121% |
(a) | The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. |
(b) | 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. |
(c) | The fair values do not include cash collateral posted on level three positions of |
Type of trade | Fair Value at December 31, 2015 | Valuation Technique | Unobservable Input | Range | Fair Value at December 31, 2016 | Valuation Technique | Unobservable Input | Range | ||||||||||||
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(c) | $ | 857 | Discounted Cash Flow | Forward power price | $11 — $88 | $ | 435 | Discounted Cash Flow | Forward power price | $11 — $130 | ||||||||||
Forward gas price | $1.18 — $8.95 | Forward gas price | $1.72 — $9.2 | |||||||||||||||||
Option Model | Volatility percentage | 5% — 152% | Option Model | Volatility percentage | 8% — 173% | |||||||||||||||
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(c) | $ | (7 | ) | Discounted Cash Flow | Forward power price | $13 — $78 | $ | (3 | ) | Discounted Cash Flow | Forward power price | $19 — $79 | ||||||||
Mark-to-market derivatives (Exelon and ComEd) | $ | (247 | ) | Discounted Cash Flow | Forward heat rate(b) | 9x — 10x | $ | (258 | ) | Discounted Cash Flow | Forward heat rate(b) | 8x — 9x | ||||||||
Marketability reserve | 3.5% — 7% | Marketability reserve | 3% — 8% | |||||||||||||||||
Renewable factor | 87% — 128% | Renewable factor | 89% — 121% |
(a) | The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. |
(b) | 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. |
(c) | The fair values do not include cash collateral posted on level three positions of |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The inputs listed above 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.
Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion StationDecommissioning (Exelon and Generation). For middle market lending and certain corporate debt securities investments, the fair value is determined using a combination of valuation models including cost models, market models and income models. The valuation estimates are based on valuations of comparable companies, discounting the forecasted cash flows, of the portfolio company, estimating the liquidation or collateral value of the portfolio company or its assets, considering offers from third parties to buy the portfolio company, its historicalmarket-based comparable data, credit and projected financial results,liquidity factors, as well as other factors that may impact value. Significant judgment is required
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
in the application of discounts or premiums applied to the prices of comparable companies for factors such as size, marketability, credit risk and relative performance.
Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Generation gains an understanding of the fund managers’ inputs and assumptions used in preparing the valuations. Generation performed procedures to assess the reasonableness of the valuations. For a sample of its Level 3 investments, Generation reviewed independent valuations and reviewed the assumptions in the detailed pricing models used by the fund managers.
Rabbi Trust Investments—Life insurance contracts (Exelon, PHI, Pepco, DPL and ACE). For lifeForlife insurance policies categorized as Level 3, the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Exelon gains an understanding of the types of inputs and assumptions used in preparing the valuations and performs procedures to assess the reasonableness of the valuations.
The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange risk and interest rate risk related to ongoing business operations.
Commodity Price Risk (All Registrants)
To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Each of the Registrants employ established policies and procedures to manage their risks
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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 energy-related products. The Registrants believe these instruments, which are classified as either economic hedges ornon-derivatives, mitigate exposure to fluctuations in commodity prices.
Derivative accounting 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 each period. 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 normal purchase normal sale (NPNS), cash flow hedge and fair value hedge. For Generation, all derivative economic hedges related to commodities are recorded at fair value through earnings for the combined company, referred to as economic hedges in the following tables. The Registrants have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. Generation has also entered into bilateral long-term contractual obligations for sales of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives and retail load aggregators, as well as contractual obligations to deliver energy to market participants who primarily focus on the resale of energy products for delivery. Thesenon-derivative contracts are accounted for primarily under the accrual method of accounting. 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels, and other commodities 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. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative andnon-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and energy purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative ornon-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and gas and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors. 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.
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, 2016,March 31, 2017, the proportion of expected generation hedged for the major reportable segments is 98%-101%, 85%-88%97%-100%,60%-63% and 54%-57%30%-33% for 2016, 2017, 2018 and 2018,2019, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacitygenerating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
power, fuel, load following products, and options. Equivalent sales represent all hedging products, which include economic hedges and certainnon-derivative contracts including Generation’s sales to the Utility RegistrantsComEd, PECO, and BGE to serve their retail load.
On December 17, 2010, ComEd entered into several20-yearfloating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 3 — Regulatory Matters of the Exelon 20152016 Form10-K for additional information.
PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with nomark-up, PECO’s price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts. PECO has certain full requirements contracts that are considered derivatives and qualify for the NPNS scope exception under current derivative authoritative guidance.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy istwo-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have nomark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2016 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach oflocking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2016 PGC settlement, PECO is required to lock in (i.e. economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’sgas-hedging program is designed to cover about 25% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.
BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE’s wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for commercial and industrial rate classes. BGE’s price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives.
BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e.non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. All of BGE’s natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery.
Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco’s wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s price risk related to electric supply procurement is limited. Pepco locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.
DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and the DPSC. The SOS rates charged recover DPL’s wholesale power supply costs. In Delaware, DPL is also entitled to recover a Reasonable Allowance for Retail Margin (RARM). The RARM includes a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. In Maryland, DPL charges an administrative fee intended to allow it to recover its administrative costs. DPL locks in fixed prices for all of its SOS requirements through full requirements
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
contracts. DPL’s price risk related to electric supply procurement is limited. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.
DPL provides natural gas to its customers under an Annual GCR mechanism approved by the DPSC. Under this mechanism, DPL’s Annual GCR Filing establishes a future GCR for firm bundled sales customers by using a forecast of demand and commodity costs. The actual costs are trued up versus the forecast on a monthly basis and any shortfall or excess is carried forward as a recovery balance in the next GCR filing. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas. The hedge program requires that DPL hedge, on anon-discretionary basis, an amount equal to fifty percent (50%) of estimated purchase requirements for each month, including estimated monthly purchases for storage injections. The fifty percent (50%) hedge monthly target is achieved by hedging 1/12th of the 50% target each month beginning12-months prior to the month in which the physical gas is to be purchased. Currently, DPL uses only exchange traded futures for its Gas Hedging Program,gas hedging program, which are considered derivatives, however, it retains the capability to employ other physical and financial hedges if needed. DPL has not elected hedge accounting for these derivative financial instruments. Because of the DPSC-approved fuel adjustment clause for DPL’s derivatives, the change in fair value of the derivatives each period, in addition to all premiums paid and other transaction costs incurred as part of the Gas Hedging Program, are fully recoverable and are recorded by DPL as regulatory assets or liabilities. DPL’s physical gas purchases are currently all daily, monthly or intra-month transactions. From time to time, DPL will enter into seasonal purchase or sale arrangements, however, there are none currently in the portfolio. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.
ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE’s wholesale power supply costs. ACE
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS requirements through full requirements contracts. Certain of ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.
Proprietary Trading. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading activities, which included settled physical sales volumes of 1,5061,850 GWhs and 4,0151,220 GWhs for the three and nine months ended September 30,March 31, 2017 and 2016, respectively, and 1,913 GWhs and 5,378 GWhs for the three and nine months ended September 30, 2015, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not enter into derivatives for proprietary trading purposes.
Interest Rate and Foreign Exchange Risk (Exelon, Generation, ComEd, PECO, BGE and PHI)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants utilizefixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At September 30, 2016,March 31, 2017, Exelon had $800 million of notional amounts offixed-to-floating hedges outstanding, and Exelon and Generation had $672$657 million of notional amounts offloating-to-fixed hedges outstanding. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) andfixed-to-floating swaps would result in an approximately $5$2 million decrease in Exelon Consolidatedpre-tax income for the ninethree months ended September 30, 2016.March 31, 2017. 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. Below is a summary of the interest rate and foreign exchange hedge balances as of September 30, 2016.
Generation | Exelon Corporate | Exelon | ||||||||||||||||||||||||||
Description | Derivatives Designated as Hedging Instruments | Economic Hedges | Proprietary Trading(a) | Collateral and Netting(b) | Subtotal | Derivatives Designated as Hedging Instruments | Total | |||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | — | $ | 15 | $ | 4 | $ | (10 | ) | $ | 9 | $ | — | $ | 9 | |||||||||||||
Mark-to-market derivative assets (noncurrent assets) | — | 13 | 4 | (11 | ) | 6 | 39 | 45 | ||||||||||||||||||||
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Total mark-to-market derivative assets | — | 28 | 8 | (21 | ) | 15 | 39 | 54 | ||||||||||||||||||||
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Mark-to-market derivative liabilities (current liabilities) | (8 | ) | (10 | ) | (3 | ) | 12 | (9 | ) | — | (9 | ) | ||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (10 | ) | (9 | ) | (3 | ) | 12 | (10 | ) | — | (10 | ) | ||||||||||||||||
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Total mark-to-market derivative liabilities | (18 | ) | (19 | ) | (6 | ) | 24 | (19 | ) | — | (19 | ) | ||||||||||||||||
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Total mark-to-market derivative net assets (liabilities) | $ | (18 | ) | $ | 9 | $ | 2 | $ | 3 | $ | (4 | ) | $ | 39 | $ | 35 | ||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)March 31, 2017:
Generation | Exelon Corporate | Exelon | ||||||||||||||||||||||||||
Description | Derivatives Designated as Hedging Instruments | Economic Hedges | Proprietary Trading(a) | Collateral and Netting(b) | Subtotal | Derivatives Designated as Hedging Instruments | Total | |||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | — | $ | 15 | $ | 3 | $ | (13 | ) | $ | 5 | $ | — | $ | 5 | |||||||||||||
Mark-to-market derivative assets (noncurrent assets) | — | 7 | 1 | (5 | ) | 3 | 12 | 15 | ||||||||||||||||||||
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Totalmark-to-market derivative assets | — | 22 | 4 | (18 | ) | 8 | 12 | 20 | ||||||||||||||||||||
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Mark-to-market derivative liabilities (current liabilities) | (1 | ) | (17 | ) | (2 | ) | 13 | (7 | ) | — | (7 | ) | ||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | — | (8 | ) | (1 | ) | 5 | (4 | ) | — | (4 | ) | |||||||||||||||||
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Totalmark-to-market derivative liabilities | (1 | ) | (25 | ) | (3 | ) | 18 | (11 | ) | — | (11 | ) | ||||||||||||||||
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Totalmark-to-market derivative net assets (liabilities) | $ | (1 | ) | $ | (3 | ) | $ | 1 | $ | — | $ | (3 | ) | $ | 12 | $ | 9 | |||||||||||
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(a) | Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. |
(b) | Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms ofnon-cash collateral. These are not reflected in the table above. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2015:2016:
Generation | Exelon Corporate | Exelon | Generation | Exelon Corporate | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||||||
Description | Derivatives Designated as Hedging Instruments | Economic Hedges | Proprietary Trading(a) | Collateral and Netting(b) | Subtotal | Derivatives Designated as Hedging Instruments | Total | Derivatives Designated as Hedging Instruments | Economic Hedges | Proprietary Trading(a) | Collateral and Netting(b) | Subtotal | Derivatives Designated as Hedging Instruments | Total | ||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | — | $ | 10 | $ | 10 | $ | (5 | ) | $ | 15 | $ | — | $ | 15 | $ | — | $ | 17 | $ | 4 | $ | (13 | ) | $ | 8 | $ | — | $ | 8 | ||||||||||||||||||||||||||
Mark-to-market derivative assets (noncurrent assets) | — | 10 | 5 | (1 | ) | 14 | 25 | 39 | — | 11 | 1 | (8 | ) | 4 | 16 | 20 | ||||||||||||||||||||||||||||||||||||||||
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Total mark-to-market derivative assets | — | 20 | 15 | (6 | ) | 29 | 25 | 54 | — | 28 | 5 | (21 | ) | 12 | 16 | 28 | ||||||||||||||||||||||||||||||||||||||||
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Mark-to-market derivative liabilities (current liabilities) | (8 | ) | (2 | ) | (9 | ) | 11 | (8 | ) | — | (8 | ) | (7 | ) | (13 | ) | (2 | ) | 14 | (8 | ) | — | (8 | ) | ||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (8 | ) | (1 | ) | (3 | ) | 4 | (8 | ) | — | (8 | ) | (3 | ) | (8 | ) | (2 | ) | 9 | (4 | ) | — | (4 | ) | ||||||||||||||||||||||||||||||||
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Total mark-to-market derivative liabilities | (16 | ) | (3 | ) | (12 | ) | 15 | (16 | ) | — | (16 | ) | (10 | ) | (21 | ) | (4 | ) | 23 | (12 | ) | — | (12 | ) | ||||||||||||||||||||||||||||||||
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Total mark-to-market derivative net assets (liabilities) | $ | (16 | ) | $ | 17 | $ | 3 | $ | 9 | $ | 13 | $ | 25 | $ | 38 | $ | (10 | ) | $ | 7 | $ | 1 | $ | 2 | $ | — | $ | 16 | $ | 16 | ||||||||||||||||||||||||||
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(a) | Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. |
(b) | Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms ofnon-cash collateral. These are not reflected in the table above. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Fair Value Hedges. For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:
Three Months Ended September 30, | ||||||||||||||||||
Income Statement Location | 2016 | 2015 | 2016 | 2015 | ||||||||||||||
Gain (loss) on Swaps | Gain (loss) on Borrowings | |||||||||||||||||
Exelon | Interest expense | $ | (8 | ) | $ | 16 | $ | 14 | $ | (13 | ) | |||||||
Nine Months Ended September 30, | ||||||||||||||||||
Income Statement Location | 2016 | 2015 | 2016 | 2015 | ||||||||||||||
Gain (loss) on Swaps | Gain (loss) on Borrowings | |||||||||||||||||
Generation | Interest expense(a) | $ | — | $ | (1 | ) | $ | — | $ | — | ||||||||
Exelon | Interest expense | 15 | 15 | (3 | ) | (4 | ) |
Income Statement Location | Three Months Ended March 31, | |||||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||||
Gain (loss) on Swaps | Gain (loss) on Borrowings | |||||||||||||||||
Exelon | Interest expense | $ | (4 | ) | $ | 17 | $ | 8 | $ | (15 | ) |
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At September 30, 2016,March 31, 2017, Exelon had total outstandingfixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $39$12 million. At December 31, 2015,2016, Exelon had total outstandingfixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $25$16 million. During the three and nine months ended September 30,March 31, 2017 and 2016, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $6$4 million gain and a $12$2 million gain, respectively.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Cash Flow Hedges. During the second quarter of 2016, Exelon entered into $90 million of floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with an anticipated debt issuance. The swaps were designated as cash flow hedges. Exelon terminated the swaps during the third quarter of 2016 upon issuance of the debt. Exelon did not recognize a gain or loss as a result of the termination.
During the first and second quarter of 2016, Exelon entered into $600 million and $100 million offloating-to-fixed forward starting interest rate swaps, respectively, to manage a portion of the interest rate exposure associated with thean anticipated issuance of debt.debt issuance. The swaps were designated as cash flow hedges. Exelon terminated the swaps during the second quarter of 2016 upon issuance of the debt. Exelon recognized a loss of $3 million related to the swaps and $3 million of AOCI will be amortized into Other, net in Exelon’s Consolidated Statement of Operations and Comprehensive Income over the term of the debt. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
During the first quarter of 2016, Exelon entered into a $100 million of floating-to-fixed forward starting interest rate swapswaps to manage a portion of the interest rate exposure associated with an anticipated debt issuance. The swap was designated as a cash flow hedge. Exelon terminated the swap during the first quarter of 2016 upon issuance of the debt. Exelon did not recognize a gain or loss as a result of the termination of the swap and an immaterial amount of AOCI will be amortized into Other, net in Exelon’s Consolidated Statement of Operations and Comprehensive Income over the term of the debt.
During the thirdfirst quarter of 2014, ExGen Texas Power, LLC,EGR, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowing. See Note 14 — Debt and Credit Agreements of the Exelon 2015 Form 10-K for additional
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
information regarding the financing. The swaps have a notional amount of $496 million as of September 30, 2016 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. At September 30, 2016, the subsidiary had a $15 million derivative liability related to the swap.
During the first quarter of 2014, ExGen Renewables I, LLC, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14 — Debt and Credit Agreements of the Exelon 20152016 Form10-K for additional information regarding the financing. The swaps have a notional amount of $176$164 million as of September 30, 2016March 31, 2017 and expire in 2020. The swaps are designated as cash flow hedges. At September 30, 2016,March 31, 2017, the subsidiary had a $3$1 million derivative liability related to the swaps.
During the second quarter of 2002, PHI entered into treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002 to manage a portion of its interest rate exposure. Upon issuance of the fixed-rate debt in August 2002, the treasury rate locks were terminated at a loss and the loss was deferred in AOCI. As a result of the PHI Merger, the remaining unamortized deferred loss recorded in AOCI was adjusted to zero through application of purchase accounting.
During the three and nine months ended September 30,March 31, 2017 and 2016, and 2015, the impact on the results of operations as a result of ineffectiveness from cash flow hedges in continuing designated hedge relationships was immaterial.
Economic Hedges. During the third quarter of 2014, EGTP, a subsidiary of Generation, entered into afloating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowing. See Note 14 — Debt and Credit Agreements of the Exelon 2016 Form10-K for additional information regarding the financing. The swaps have a notional amount of $494 million as of March 31, 2017 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. During the first quarter of 2017, the swap wasde-designated. At March 31, 2017, the subsidiary had a $7 million derivative liability related to the swap.
During the third quarter of 2011, Sacramento PV Energy, a subsidiary of Generation entered intofloating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14 — Debt and Credit Agreements of the Exelon 20152016 Form10-K for additional information regarding the financing. During the first quarter of 2016, upon the issuancetermination of debt, Generation terminated the swaps. The total notional amount of the swaps were $25 million. No gain or loss was recognized as a result of the termination of the swaps.
During the third quarter of 2012, Constellation Solar Horizons, a subsidiary of Generation, entered into afloating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14 — Debt and Credit Agreements of the Exelon 20152016 Form10-K for additional information regarding the financing. During the first quarter of 2016, upon the issuancetermination of debt, Generation terminated the swap. The total notional amount of the swap was $24 million. No gain or loss was recognized as a result of the termination of the swap.
During the second quarter 2015, upon the issuance of debt, Exelon terminated $2,400 million of floating-to-fixed forward starting interest rate swaps. As a result of the termination of the swaps, Exelon realized a $64 million loss during the second quarter of 2015.
At September 30, 2016,March 31, 2017, Generation had noimmaterial notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $85$73 million in
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
notional amounts of foreign currency exchange rate swaps that aremarked-to-market to manage the exposure associated with international commodity transactionspurchases of commodities in currencies other than U.S. dollars.
Fair Value Measurement and Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon, Generation, ComEd, PECO, BGE, PHI and DPL)
Fair value accounting guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two counterparties that may have derivative andnon-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, Generation’s energy related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including initial margin on exchange positions, is aggregated in the collateral and netting column. As of September 30, 2016both March 31, 2017 and December 31, 2015, $5 million and $32016, $8 million of cash collateral held and posted, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or as of the balance sheet date there were no positions to offset. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and othernon-derivative contracts that are accounted for under the accrual method of accounting.
ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e., to BB+ or Ba1).
Cash collateral held by PECO and BGE must be deposited in a non affiliate major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
In the table below, DPL’s economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, is aggregated in the collateral and netting column.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of September 30, 2016:March 31, 2017:
Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Generation | ComEd | DPL | PHI | Exelon | Generation | ComEd | DPL | PHI | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives | Economic Hedges | Proprietary Trading | Collateral and Netting(a) | Subtotal(b) | Economic Hedges(c) | Economic Hedges(d) | Collateral and Netting(a) | Subtotal | Subtotal | Total Derivatives | Economic Hedges | Proprietary Trading | Collateral and Netting(a)(e) | Subtotal(b) | Economic Hedges(c) | Economic Hedges(d) | Collateral and Netting(a) | Subtotal | Subtotal | Total Derivatives | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | 3,482 | $ | 67 | $ | (2,804 | ) | $ | 745 | $ | — | $ | 1 | $ | (1 | ) | $ | — | $ | — | $ | 745 | $ | 3,398 | $ | 56 | $ | (2,612 | ) | $ | 842 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 842 | |||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets (noncurrent assets) | 2,139 | 31 | (1,546 | ) | 624 | — | — | — | — | — | 624 | 1,975 | 24 | (1,475 | ) | 524 | — | — | — | — | — | 524 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total mark-to-market derivative assets | 5,621 | 98 | (4,350 | ) | 1,369 | — | 1 | (1 | ) | — | — | 1,369 | 5,373 | 80 | (4,087 | ) | 1,366 | — | — | — | — | — | 1,366 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mark-to-market derivative liabilities (current liabilities) | (3,229 | ) | (61 | ) | 3,096 | (194 | ) | (19 | ) | — | — | — | — | (213 | ) | (3,029 | ) | (49 | ) | 2,876 | (202 | ) | (19 | ) | — | — | — | — | (221 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (1,885 | ) | (41 | ) | 1,739 | (187 | ) | (225 | ) | — | — | — | — | (412 | ) | (1,780 | ) | (28 | ) | 1,655 | (153 | ) | (263 | ) | — | — | — | — | (416 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||
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Total mark-to-market derivative liabilities | (5,114 | ) | (102 | ) | 4,835 | (381 | ) | (244 | ) | — | — | — | — | (625 | ) | (4,809 | ) | (77 | ) | 4,531 | (355 | ) | (282 | ) | — | — | — | — | (637 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||
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Total mark-to-market derivative net assets (liabilities) | $ | 507 | $ | (4 | ) | $ | 485 | $ | 988 | $ | (244 | ) | $ | 1 | $ | (1 | ) | $ | — | $ | — | $ | 744 | $ | 564 | $ | 3 | $ | 444 | $ | 1,011 | $ | (282 | ) | $ | — | $ | — | $ | — | $ | — | $ | 729 | ||||||||||||||||||||||||||||||||||||
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(a) | Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms ofnon-cash collateral. These are not reflected in the table above. |
(b) | Current and noncurrent assets are shown net of collateral of |
(c) | Includes current and noncurrent liabilities relating tofloating-to-fixed energy swap contracts with unaffiliated suppliers. |
(d) | Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC. |
(e) | Of the collateral posted/(received), $14 million represents variation margin on the exchanges. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2015:2016:
Predecessor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Generation | ComEd | Exelon | DPL | PHI Corporate | PHI | Generation | ComEd | DPL | PHI | Exelon | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Description | Economic Hedges | Proprietary Trading | Collateral and Netting(a) | Subtotal(b) | Economic Hedges(c) | Total Derivatives | Economic Hedges(e) | Collateral and Netting(a) | Subtotal | Other(d) | Total Derivatives | Economic Hedges | Proprietary Trading | Collateral and Netting(a)(e) | Subtotal(b) | Economic Hedges(c) | Economic Hedges(d) | Collateral and Netting(a) | Subtotal | Subtotal | Total Derivatives | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets (current assets) | $ | 5,236 | $ | 108 | $ | (3,994 | ) | $ | 1,350 | $ | — | $ | 1,350 | $ | — | $ | — | $ | — | $ | 18 | $ | 18 | $ | 3,623 | $ | 55 | $ | (2,769 | ) | $ | 909 | $ | — | $ | 2 | $ | (2 | ) | $ | — | $ | — | $ | 909 | |||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative assets (noncurrent assets) | 1,860 | 22 | (1,163 | ) | 719 | — | 719 | — | — | — | — | — | 1,467 | 21 | (1,016 | ) | 472 | — | — | — | — | — | 472 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total mark-to-market derivative assets | 7,096 | 130 | (5,157 | ) | 2,069 | — | 2,069 | — | — | — | 18 | 18 | 5,090 | 76 | (3,785 | ) | 1,381 | — | 2 | (2 | ) | — | — | 1,381 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mark-to-market derivative liabilities (current liabilities) | (4,907 | ) | (94 | ) | 4,827 | (174 | ) | (23 | ) | (197 | ) | (2 | ) | 2 | — | — | — | (3,165 | ) | (54 | ) | 2,964 | (255 | ) | (19 | ) | — | — | — | — | (274 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (noncurrent liabilities) | (1,673 | ) | (33 | ) | 1,564 | (142 | ) | (224 | ) | (366 | ) | — | — | — | — | — | (1,274 | ) | (25 | ) | 1,150 | (149 | ) | (239 | ) | — | — | — | — | (388 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total mark-to-market derivative liabilities | (6,580 | ) | (127 | ) | 6,391 | (316 | ) | (247 | ) | (563 | ) | (2 | ) | 2 | — | — | — | (4,439 | ) | (79 | ) | 4,114 | (404 | ) | (258 | ) | — | — | — | — | (662 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total mark-to-market derivative net assets (liabilities) | $ | 516 | $ | 3 | $ | 1,234 | $ | 1,753 | $ | (247 | ) | $ | 1,506 | $ | (2 | ) | $ | 2 | $ | — | $ | 18 | $ | 18 | $ | 651 | $ | (3 | ) | $ | 329 | $ | 977 | $ | (258 | ) | $ | 2 | $ | (2 | ) | $ | — | $ | — | $ | 719 | |||||||||||||||||||||||||||||||||||||
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(a) | Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit and other forms ofnon-cash collateral. These are not reflected in the table above. |
(b) | Current and noncurrent assets are shown net of collateral of |
(c) | Includes current and noncurrent liabilities relating tofloating-to-fixed energy swap contracts with unaffiliated suppliers. |
(d) |
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Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC. |
(e) | Of the collateral posted/(received), $(158) million represents variation margin on the exchanges. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Cash Flow Hedges (Exelon and Generation). The tables below provide the activity of AOCIOCI related to cash flow hedges for the ninethree months ended September 30,March 31, 2017 and 2016, and 2015, containing information about the changes in the fair value of cash flow hedges and the reclassification from AOCIAccumulated OCI into results of operations. The amounts reclassified from AOCI,OCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.
Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||
Generation | Exelon | |||||||||||
Three Months Ended September 30, 2016 | Income Statement Location | Total Cash Flow Hedges | Total Cash Flow Hedges | |||||||||
AOCI derivative loss at June 30, 2016 | $ | (25 | ) | $ | (26 | ) | ||||||
Effective portion of changes in fair value | 1 | 3 | ||||||||||
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AOCI derivative loss at September 30, 2016 | $ | (24 | ) | $ | (23 | ) | ||||||
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Income Statement Location | Total Cash Flow Hedge OCI Activity, Net of Income Tax | |||||||||||
Generation | Exelon | |||||||||||
Three Months Ended March 31, 2017 | Total Cash Flow Hedges | Total Cash Flow Hedges | ||||||||||
Accumulated OCI derivative loss at December 31, 2016 | $ | (19 | ) | $ | (17 | ) | ||||||
Effective portion of changes in fair value | 2 | 2 | ||||||||||
Reclassifications from AOCI to net income | Interest Expense | 4 | (a) | 4 | (a) | |||||||
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Accumulated OCI derivative loss at March 31, 2017 | $ | (13 | ) | $ | (11 | ) | ||||||
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Total Cash Flow Hedge OCI Activity, Net of Income Tax | Income Statement Location | Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||||||||||||
Generation | Exelon | Generation | Exelon | |||||||||||||||||||||
Nine Months Ended September 30, 2016 | Income Statement Location | Total Cash Flow Hedges | Total Cash Flow Hedges | |||||||||||||||||||||
Three Months Ended March 31, 2016 | Income Statement Location | Total Cash Flow Hedges | Total Cash Flow Hedges | |||||||||||||||||||||
Accumulated OCI derivative loss at December 31, 2015 | $ | (21 | ) | $ | (19 | ) | $ | (21 | ) | $ | (19 | ) | ||||||||||||
Effective portion of changes in fair value | — | (1 | ) | (8 | ) | (10 | ) | |||||||||||||||||
Reclassifications from AOCI to net income | Interest Expense | (3 | )(a) | (3 | )(a) | Interest Expense | 3 | (b) | 3 | (b) | ||||||||||||||
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Accumulated OCI derivative loss at September 30, 2016 | $ | (24 | ) | $ | (23 | ) | ||||||||||||||||||
Accumulated OCI derivative loss at March 31, 2016 | $ | (26 | ) | $ | (26 | ) | ||||||||||||||||||
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Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||
Generation | Exelon | |||||||||||
Three Months Ended September 30, 2015 | Income Statement Location | Total Cash Flow Hedges | Total Cash Flow Hedges | |||||||||
AOCI derivative loss at June 30, 2015 | (21 | ) | $ | (19 | ) | |||||||
Effective portion of changes in fair value | (7 | ) | (8 | ) | ||||||||
Reclassifications from AOCI to net income | Interest Expense | 3 | 3 | |||||||||
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AOCI derivative loss at September 30, 2015 | $ | (25 | ) | $ | (24 | ) | ||||||
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Total Cash Flow Hedge OCI Activity, Net of Income Tax | ||||||||||||
Generation | Exelon | |||||||||||
Nine Months Ended September 30, 2015 | Income Statement Location | Total Cash Flow Hedges | Total Cash Flow Hedges | |||||||||
Accumulated OCI derivative loss at December 31, 2014 | $ | (18 | ) | $ | (28 | ) | ||||||
Effective portion of changes in fair value | (13 | ) | (18 | ) | ||||||||
Reclassifications from AOCI to net income | Other, net | — | 16 | (b) | ||||||||
Reclassifications from AOCI to net income | Interest Expense | 8 | 8 | |||||||||
Reclassifications from AOCI to net income | Operating Revenues | (2 | ) | (2 | ) | |||||||
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Accumulated OCI derivative loss at September 30, 2015 | $ | (25 | ) | $ | (24 | ) | ||||||
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(a) | Amount is net of related income tax expense of $3 million for the three months ended March 31, 2017. |
(b) | Amount is net of related income tax expense of $2 million for the three months ended March 31, 2016. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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The effect of Exelon’s and Generation’s former energy-related cash flow hedge activity on pre-tax earnings based on the reclassification adjustment from AOCI to earnings was a $2 million pre-tax gain for the nine months ended September 30, 2015. There were no gains recognized for the three months ended September 30, 2015. Neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness in future periods relating to energy-related hedges positions as all were de-designated prior to the Constellation merger date.
Economic Hedges (Exelon and Generation).These instruments represent hedges that economically mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, physical forward sales and purchases, but for which the fair value or cash flow hedge elections were not made. Additionally, Generation enters into interest rate derivative contracts and foreign exchange currency swaps (“treasury”) to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars. For the three and nine months ended September 30,March 31, 2017 and 2016, and 2015, the following netpre-taxmark-to-market gains (losses) of certain purchase and sale contracts were reported in Operating revenues or Purchased power and fuel expense, or Interest expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement”realized” generally represents the recognized change in fair value that was reclassified from unrealized to realized duewhen the transaction to settlement ofwhich the derivative during the period.relates occurs.
Generation | Exelon | |||||||||||||||
Three Months Ended September 30, 2016 | Operating Revenues | Purchased Power and Fuel | Total | Total | ||||||||||||
Change in fair value of commodity positions | $ | 280 | $ | (73 | ) | $ | 207 | $ | 207 | |||||||
Reclassification to realized at settlement of commodity positions | (92 | ) | (26 | ) | (118 | ) | (118 | ) | ||||||||
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Net commodity mark-to-market gains (losses) | 188 | (99 | ) | 89 | 89 | |||||||||||
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Change in fair value of treasury positions | 1 | — | 1 | 1 | ||||||||||||
Reclassification to realized at settlement of treasury positions | (2 | ) | — | (2 | ) | (2 | ) | |||||||||
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Net treasury mark-to-market gains (losses) | (1 | ) | — | (1 | ) | (1 | ) | |||||||||
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Net mark-to-market gains (losses) | $ | 187 | $ | (99 | ) | $ | 88 | $ | 88 | |||||||
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Generation | Exelon | |||||||||||||||
Three Months Ended March 31, 2017 | Operating Revenues | Purchased Power and Fuel | Total | Total | ||||||||||||
Change in fair value of commodity positions | $ | 93 | $ | (135 | ) | $ | (42 | ) | $ | (42 | ) | |||||
Reclassification to realized of commodity positions | (47 | ) | 42 | (5 | ) | (5 | ) | |||||||||
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Net commoditymark-to-market gains (losses) | 46 | (93 | ) | (47 | ) | (47 | ) | |||||||||
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Change in fair value of treasury positions | (1 | ) | — | (1 | ) | (1 | ) | |||||||||
Reclassification to realized of treasury positions | (1 | ) | — | (1 | ) | (1 | ) | |||||||||
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Net treasurymark-to-market gains (losses) | (2 | ) | — | (2 | ) | (2 | ) | |||||||||
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Netmark-to-market gains (losses) | $ | 44 | $ | (93 | ) | $ | (49 | ) | $ | (49 | ) | |||||
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Generation | Exelon | |||||||||||||||
Nine Months Ended September 30, 2016 | Operating Revenues | Purchased Power and Fuel | Total | Total | ||||||||||||
Change in fair value of commodity positions | $ | 127 | $ | 36 | $ | 163 | $ | 163 | ||||||||
Reclassification to realized at settlement of commodity positions | (484 | ) | 217 | (267 | ) | (267 | ) | |||||||||
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Net commodity mark-to-market gains (losses) | (357 | ) | 253 | (104 | ) | (104 | ) | |||||||||
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Change in fair value of treasury positions | (3 | ) | — | (3 | ) | (3 | ) | |||||||||
Reclassification to realized at settlement of treasury positions | (6 | ) | — | (6 | ) | (6 | ) | |||||||||
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Net treasury mark-to-market gains (losses) | (9 | ) | — | (9 | ) | (9 | ) | |||||||||
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Net mark-to-market gains (losses) | $ | (366 | ) | $ | 253 | $ | (113 | ) | $ | (113 | ) | |||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation | Exelon Corporate | Exelon | ||||||||||||||||||
Three Months Ended September 30, 2015 | Operating Revenues | Purchased Power and Fuel | Total | Interest Expense | Total | |||||||||||||||
Change in fair value of commodity positions | $ | 136 | $ | (178 | ) | $ | (42 | ) | $ | — | $ | (42 | ) | |||||||
Reclassification to realized at settlement of commodity positions | (143 | ) | 46 | (97 | ) | (97 | ) | |||||||||||||
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Net commodity mark-to-market gains (losses) | (7 | ) | (132 | ) | (139 | ) | — | (139 | ) | |||||||||||
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Change in fair value of treasury positions | 2 | — | 2 | — | 2 | |||||||||||||||
Reclassification to realized at settlement of treasury positions | (2 | ) | — | (2 | ) | — | (2 | ) | ||||||||||||
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Net treasury mark-to-market gains (losses) | — | — | — | — | — | |||||||||||||||
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Net mark-to-market gains (losses) | $ | (7 | ) | $ | (132 | ) | $ | (139 | ) | $ | — | $ | (139 | ) | ||||||
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Generation | Exelon Corporate | Exelon | ||||||||||||||||||
Nine Months Ended September 30, 2015 | Operating Revenues | Purchased Power and Fuel | Total | Interest Expense | Total | |||||||||||||||
Change in fair value of commodity positions | $ | 513 | $ | (163 | ) | $ | 350 | $ | — | $ | 350 | |||||||||
Reclassification to realized at settlement of commodity positions | (347 | ) | 249 | (98 | ) | — | (98 | ) | ||||||||||||
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Net commodity mark-to-market gains (losses) | 166 | 86 | 252 | — | 252 | |||||||||||||||
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Change in fair value of treasury positions | 12 | — | 12 | 36 | 48 | |||||||||||||||
Reclassification to realized at settlement of treasury positions | (6 | ) | — | (6 | ) | 64 | 58 | |||||||||||||
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Net treasury mark-to-market gains (losses) | 6 | — | 6 | 100 | 106 | |||||||||||||||
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Net mark-to-market gains (losses) | $ | 172 | $ | 86 | $ | 258 | $ | 100 | $ | 358 | ||||||||||
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Generation | Exelon | |||||||||||||||
Three Months Ended March 31, 2016 | Operating Revenues | Purchased Power and Fuel | Total | Total | ||||||||||||
Change in fair value of commodity positions | $ | 279 | $ | (127 | ) | $ | 152 | $ | 152 | |||||||
Reclassification to realized of commodity positions | (211 | ) | 167 | (44 | ) | (44 | ) | |||||||||
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Net commoditymark-to-market gains (losses) | 68 | 40 | 108 | 108 | ||||||||||||
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Change in fair value of treasury positions | (3 | ) | — | (3 | ) | (3 | ) | |||||||||
Reclassification to realized of treasury positions | (2 | ) | — | (2 | ) | (2 | ) | |||||||||
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Net treasurymark-to-market gains (losses) | (5 | ) | — | (5 | ) | (5 | ) | |||||||||
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Netmark-to-market gains (losses) | $ | 63 | $ | 40 | $ | 103 | $ | 103 | ||||||||
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Proprietary Trading Activities (Exelon and Generation). For the three and nine months ended September 30,March 31, 2017 and 2016, and 2015, Exelon and Generation recognized the following net unrealizedmark-to-market gains (losses), net realizedmark-to-market gains (losses) and total netmark-to-market gains (losses) before income taxes relating tomark-to-market activity on commodity derivative instruments entered into for proprietary trading purposes and interest rate and foreign exchange derivative contracts to hedge risk associated with the interest rate and foreign exchange components of underlying commodity positions. Gains and losses associated with proprietary trading are reported as operating revenuerevenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement”realized” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Change in fair value of commodity positions | $ | 4 | $ | (4 | ) | $ | 18 | $ | 5 | |||||||
Reclassification to realized at settlement of commodity positions | (6 | ) | (2 | ) | (17 | ) | (8 | ) | ||||||||
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Net commodity mark-to-market gains (losses) | (2 | ) | (6 | ) | 1 | (3 | ) | |||||||||
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Change in fair value of treasury positions | — | 3 | (2 | ) | 7 | |||||||||||
Reclassification to realized at settlement of treasury positions | 1 | (3 | ) | 2 | (9 | ) | ||||||||||
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Net treasury mark-to-market gains (losses) | 1 | — | — | (2 | ) | |||||||||||
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Total net mark-to-market gains (losses) | $ | (1 | ) | $ | (6 | ) | $ | 1 | $ | (5 | ) | |||||
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Three Months Ended March 31, | ||||||||
2017 | 2016 | |||||||
Change in fair value of commodity positions | $ | — | $ | 7 | ||||
Reclassification to realized of commodity positions | (1 | ) | (3 | ) | ||||
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Net commoditymark-to-market gains (losses) | (1 | ) | 4 | |||||
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Change in fair value of treasury positions | — | (2 | ) | |||||
Reclassification to realized of treasury positions | (1 | ) | 1 | |||||
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Net treasurymark-to-market gains (losses) | (1 | ) | (1 | ) | ||||
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Total netmark-to-market gains (losses) | $ | (2 | ) | $ | 3 | |||
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Credit Risk (All Registrants)
The Registrants would be exposed to credit-related losses in the event ofnon-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, 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)
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, 2016.March 31, 2017. 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, further discussed in ITEM 3. — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.exchanges. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $24$13 million, $45$31 million, $22$24 million, $47$40 million, $12$13 million, and $10$7 million as of September 30, 2016,March 31, 2017, respectively.
Rating as of September 30, 2016 | 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 March 31, 2017 | 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 | $ | 1,017 | $ | 4 | $ | 1,013 | 1 | $ | 355 | $ | 964 | $ | 16 | $ | 948 | 1 | $ | 313 | ||||||||||||||||||||||
Non-investment grade | 175 | 22 | 153 | — | — | 75 | 3 | 72 | — | — | ||||||||||||||||||||||||||||||
No external ratings | ||||||||||||||||||||||||||||||||||||||||
Internally rated — investment grade | 423 | 3 | 420 | — | — | 324 | — | 324 | — | — | ||||||||||||||||||||||||||||||
Internally rated — non-investment grade | 61 | 3 | 58 | — | — | |||||||||||||||||||||||||||||||||||
Internally rated — non- | 127 | 14 | 113 | — | — | |||||||||||||||||||||||||||||||||||
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Total | $ | 1,676 | $ | 32 | $ | 1,644 | 1 | $ | 355 | $ | 1,490 | $ | 33 | $ | 1,457 | 1 | $ | 313 | ||||||||||||||||||||||
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Net Credit Exposure by Type of Counterparty | As of September 30, 2016 | As of March 31, 2017 | ||||||
Financial institutions | $ | 117 | $ | 101 | ||||
Investor-owned utilities, marketers, power producers | 757 | 600 | ||||||
Energy cooperatives and municipalities | 712 | 663 | ||||||
Other | 58 | 93 | ||||||
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| |||||||
Total | $ | 1,644 | $ | 1,457 | ||||
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(a) | As of |
ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of September 30, 2016,March 31, 2017, ComEd’s net credit exposure to suppliers was approximately $1 million.
ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 20152016 Form10-K for additional information.
PECO’s supplier master agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents PECO’s net credit exposure. As of September 30, 2016,March 31, 2017, PECO had no material net credit exposure to suppliers.
PECO is permitted to recover its costs of procuring electric supply through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 5 — Regulatory Matters for additional information.
PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of September 30, 2016,March 31, 2017, PECO had no material credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.
BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 20152016 Form10-K for additional information.
BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth, subject to an unsecured credit cap. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents BGE’s net credit exposure. The seller’s credit exposure is calculated each business day. As of September 30, 2016,March 31, 2017, BGE had no net credit exposure to suppliers.
BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does makeoff-system sales after BGE has satisfied its customers’ demands, which are not covered by the gas cost adjustment clause. At September 30, 2016,March 31, 2017, BGE had credit exposure of less than $1$3 million related tooff-system sales which is mitigated by parental guarantees, letters of credit or right to offset clauses within other contracts with those third-party suppliers.
Pepco’s, DPL’s and ACE’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents Pepco’s, DPL’s and ACE’s net credit exposure. As of September 30, 2016,March 31, 2017, Pepco’s, DPL’s and ACE’s net credit exposures to suppliers were immaterial.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy through the NJBPU-approved procurement tariffs. Pepco’s, DPL’s and ACE’s counterparty credit risks are mitigated by their ability to recover realized energy costs through customer rates. See Note 63 — Regulatory Matters of the PHI 2015Exelon 2016 Form10-K for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
DPL’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the DPSC. DPL’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the GCR, which allows DPL to adjust rates annually to reflect realized natural gas prices. To the extent that the fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder. As of September 30, 2016,March 31, 2017, DPL had no credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.
Collateral and Contingent-Related Features (All Registrants)
As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, 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 (i.e., NYMEX, ICE). 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 expresslyagreed-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.
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 Feature | September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | ||||||||||||
Gross Fair Value of Derivative Contracts Containing this Feature(a) | $ | (975 | ) | $ | (932 | ) | $ | (994 | ) | $ | (960 | ) | ||||
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements(b) | 664 | 684 | 712 | 627 | ||||||||||||
|
|
|
| |||||||||||||
Net Fair Value of Derivative Contracts Containing This Feature(c) | $ | (311 | ) | $ | (248 | ) | $ | (282 | ) | $ | (333 | ) | ||||
|
|
|
|
(a) | Amount represents the gross fair value ofout-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(b) | Amount represents the offsetting fair value ofin-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 ofout-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based. |
Generation had cash collateral posted of $501$471 million and letters of credit posted of $420$273 million and cash collateral held of $18$35 million and letters of credit held of $22$32 million as of September 30, 2016March 31, 2017 for external counterparties with derivative positions. Generation had cash collateral posted of $1,267$347 million and letters of credit posted of $497$284 million and cash collateral held of $21$24 million and letters of credit held of $78$28 million at December 31, 20152016 for external counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e., to
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
BB+ by S&P or Ba1 by Moody’s), Generation would have been required to post additional collateral of $1.9$1.8 billion and $2.0$1.9 billion as of September 30, 2016March 31, 2017 and December 31, 2015,2016, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative andnon-derivative positions under master netting agreements.
Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Generation’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of September 30, 2016,March 31, 2017, Generation’s swaps were in a liability position with a fair value of $4$3 million and Exelon’s swaps were in an asset position, with a fair value of $35$9 million.
See Note 2526 — Segment Information of the Exelon 20152016 Form10-K for further information regarding the letters of credit supporting the cash collateral.
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, withone-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. Under the terms of ComEd’s standard block energy contracts, collateral postings areone-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of September 30, 2016,March 31, 2017, ComEd held $3approximately $1 million in collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion isone-sided from suppliers should the forward market prices exceed contract prices. As of September 30, 2016,March 31, 2017, ComEd held approximately $19 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. If ComEd lost its investment grade credit rating as of September 30, 2016,March 31, 2017, it would have been required to post approximately $17$10 million of collateral to its counterparties. See Note 3 — Regulatory Matters of the Exelon 20152016 Form10-K for additional information.
PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of September 30, 2016,March 31, 2017, PECO was not required to post collateral for any of
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
these agreements. If PECO lost its investment grade credit rating as of September 30, 2016,March 31, 2017, PECO could have been required to post approximately $25$27 million of collateral to its counterparties.
PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.
BGE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE to post collateral.
BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of September 30, 2016,March 31, 2017, BGE was not required to post collateral for any of these agreements. If
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
BGE lost its investment grade credit rating as of September 30, 2016,March 31, 2017, BGE could have been required to post approximately $29$47 million of collateral to its counterparties.
Pepco’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require Pepco to post collateral.
DPL’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require DPL to post collateral.
DPL’s natural gas procurement contracts contain provisions that could require DPL to post collateral. To the extent that the fair value of the natural gas derivative transaction in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The DPL obligations are standalone, without the guaranty of PHI. If DPL lost its investment grade credit rating as of September 30, 2016,March 31, 2017, DPL could have been required to post an additional amount of approximately $9$11 million of collateral to its natural gas counterparties.
ACE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require ACE to post collateral.
Short-Term Borrowings
Exelon, Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes. 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. PHI meets its short-term liquidity requirement primarily through the issuance of short-term notes and the Exelon intercompany money pool. Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Commercial Paper
The Registrants had the following amounts of commercial paper borrowings outstanding as of September 30, 2016March 31, 2017 and December 31, 2015:2016:
Commercial Paper Borrowings | September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | ||||||||||||
Exelon Corporate | $ | 204 | $ | — | ||||||||||||
Generation | 579 | 620 | ||||||||||||||
ComEd | $ | 10 | $ | 294 | 365 | — | ||||||||||
PECO | — | — | ||||||||||||||
BGE | — | 210 | 95 | 45 | ||||||||||||
PHI Corporate | — | 484 | — | — | ||||||||||||
Pepco | — | 64 | 167 | 23 | ||||||||||||
DPL | 17 | 105 | ||||||||||||||
ACE | — | 5 |
Short-Term Loan Agreements
On July 30, 2015, PHI entered into a $300 million term loan agreement. The net proceeds of the loan were used to repay PHI’s outstanding commercial paper and for general corporate purposes. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95%, and all indebtedness thereunder is unsecured. On April 4, 2016, PHI repaid $300 million of its term loan in full.
On January 13, 2016, PHI entered into a $500 million term loan agreement, which was amended on March 28, 2016. The net proceeds of the loan were used to repay PHI’s outstanding commercial paper, and for
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
general corporate purposes. Pursuant to the loan agreement, as amended, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1%, and all indebtedness thereunder is unsecured, andunsecured. On March 23, 2017, the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement must bewas fully repaid in fulland the loan terminated. On March 23, 2017, Exelon Corporate entered into a similar type term loan for $500 million which expires on or before March 27, 2017. The22, 2018. Pursuant to the loan agreement, is reflected in Exelon’s and PHI’s Consolidated Balance Sheets within Short-term borrowings.
On February 22, 2016, Generation and EDF entered into separate member revolving promissory notes with CENG to finance short-term working capital needs. The notes are scheduled to mature on January 31, 2017 andloans made thereunder bear interest at a variable rate equal to LIBOR plus 1.75%. On July 25, 2016, CENG paid off the outstanding balances under each note.1% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon’s Consolidated Balance Sheet within Short-Term borrowings.
Credit Agreements
On January 5, 2016, Generation entered into a credit agreement establishing a $150 million bilateral credit facility, scheduled to mature in January of 2019. This facility will solely be utilized by Generation to issue letters of credit. This facility does not back Generation’s commercial paper program.
On January 9, 2017, the credit agreement for Generation’s $75 million bilateral credit facility was amended and restated to increase the facility size to $100 million and extend the maturity to January 2019. This facility will solely be used by Generation to issue letters of credit.
On April 1, 2016, the credit agreement for CENG’s $100 million bilateral credit facility was amended to increase the overall facility size to $200 million. This facility is utilized by CENG to fund working capital and capital projects. The facility does not back Generation’s commercial paper program.
On May 26, 2016, Exelon Corporate, Generation, ComEd, PECO and BGE entered into amendments to each of their respective syndicated revolving credit facilities, which extended the maturity of each of the facilities to May 26, 2021. Exelon Corporate also increased the size of its facility from $500 million to $600 million. On May 26, 2016, PHI, Pepco, DPL and ACE entered into an amendment to their Second Amended and Restated Credit Agreement dated as of August 1, 2011, which (i) extended the maturity date of the facility to May 26, 2021, (ii) removed PHI as a borrower under the facility, (iii) decreased the size of the facility from $1.5 billion to $900 million and (iv) alignedconverted its financial covenant from a debt to capitalization leverage ratio to an interest coverage ratio.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Variable Rate Demand Bonds
As of September 30, 2016 and December 31, 2015, $105 million in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year on Exelon’s, PHI’s and DPL’s Consolidated Balance Sheets. See Note 10 — Debt of the PHI 2015 Form 10-K for additional information.
Long-Term Debt
Issuance of Long-Term Debt
During the ninethree months ended September 30, 2016,March 31, 2017, the following long-term debt was issued:
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | |||||||||
Exelon Corporate | Senior Unsecured Notes | 2.45% | April 15, 2021 | $300 | Repay commercial paper issued by PHI and for general corporate purposes | |||||||||
Exelon Corporate | Senior Unsecured Notes | 3.40% | April 15, 2026 | $750 | Repay commercial paper issued by PHI and for general corporate purposes | |||||||||
Exelon Corporate | Senior Unsecured Notes | 4.45% | April 15, 2046 | $750 | Repay commercial paper issued by PHI and for general corporate purposes | |||||||||
Generation | Renewable Power Generation Nonrecourse Debt | 4.11% | March 31, 2035 | $150 | Paydown long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general corporate purposes | |||||||||
Generation | Albany Green Energy Project Financing | LIBOR + 1.25% | November 17, 2017 | $ 86 | Albany Green Energy biomass generation development | |||||||||
Generation | Energy Efficiency Project Financing | 3.17% | December 31, 2017 | $ 16 | Funding to install energy conservation measures in Brooklyn, NY | |||||||||
Generation | Energy Efficiency Project Financing | 3.42% | January 31, 2018 | $ 13 | Funding to install energy conservation measures for the Naval Station Great Lakes project | |||||||||
ComEd | First Mortgage Bonds, Series 120 | 2.55% | June 15, 2026 | $500 | Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | |||||||||
ComEd | First Mortgage Bonds, Series 121 | 3.65% | June 15, 2046 | $700 | Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes | |||||||||
Generation | Energy Efficiency Project Financing | 3.52% | April 30, 2018 | $ 11 | Funding to install energy conservation measures for the Smithsonian Zoo project | |||||||||
Pepco | Energy Efficiency Project Financing | 3.30% | December 15, 2017 | $ 2 | Funding to install energy conservation measures for the DOE Germantown project | |||||||||
BGE | Notes | 2.40% | August 15, 2026 | $350 | Redeem the $190M of outstanding preference shares and for general corporate purposes | |||||||||
BGE | Notes | 3.50% | August 15, 2046 | $500 | Redeem the $190M of outstanding preference shares and for general corporate purposes | |||||||||
PECO(a) | First Mortgage Bonds | 1.70% | September 15, 2021 | $300 | Refinance maturing mortgage bonds | |||||||||
Generation | SolGen Nonrecourse Debt | 3.93% | September 30, 2036 | $150 | General corporate purposes | |||||||||
Generation | ExGen Texas Power Nonrecourse Debt | LIBOR + 4.25% | September 18, 2019 | $ 4 | General corporate purposes for EGTP |
|
Company | Type | Interest Rate | Maturity | Amount | Use of Proceeds | |||||||||
Generation | Energy Efficiency Project Financing | 3.72% | April 30, 2018 | $ | 1 | Funding to install energy conservation measures for the Smithsonian Zoo project | ||||||||
Generation | Energy Efficiency Project Financing | 2.61% | September 30, 2018 | $ | 1 | Funding to install energy conservation measures for the Pensacola project | ||||||||
Generation | Energy Efficiency Project Financing | 3.90% | January 31, 2018 | $ | 6 | Funding to install energy conservation measures for the Naval Station Great Lakes project | ||||||||
Generation | Albany Green Energy Project Financing | LIBOR + 1.25% | November 17, 2017 | $ | 13 | Albany Green Energy biomass generation development | ||||||||
Generation | Senior Notes | 2.95% | January 15, 2020 | $ | 250 | Repay outstanding commercial paper obligations and for general corporate purposes. | ||||||||
Generation | Senior Notes | 3.40% | March 15, 2022 | $ | 500 | Repay outstanding commercial paper obligations and for general corporate purposes. | ||||||||
Pepco | Energy Efficiency Project Financing | 3.30% | December 15, 2017 | $ | 1 | Funding to install energy conservation measures for the DOE Germantown project |
CEU UpstreamEGTP Nonrecourse Debt
In July 2011, CEU Holdings, LLC, a wholly ownedSeptember 2014, EGTP, an indirect subsidiary of Exelon and Generation, entered into a 5-year reserve based lending agreement (RBL) associated with certain Upstream oil and gas properties that it owns. The lenders do not have recourse against Exelon or Generation in the event of default pursuant to the RBL. Borrowings under this arrangement are secured by the assets and equity of CEU Holdings. The commitment level can be decreased if the assets no longer support the current borrowing base, which may result in repaymentissued $675 million aggregate principal amount of a portion or all of the outstanding balance, or potential foreclosure of the assets.nonrecourse senior secured term loan. The commitment can be increased upnet proceeds were distributed to $500 million if the assets support a higher borrowing base and CEU HoldingsGeneration for general business purposes. The loan is ablescheduled to obtain additional commitments from lenders. Calculations of the borrowing base are impacted by projected production and commodity prices.mature on September 18, 2021. The facility was amended and extended on January 14, 2014 through January 2019. As of December 31, 2015, $68 million was outstanding under the facility withterm loan bears interest payable monthly at a variable rate equal to LIBOR plus 2.50%4.75%, subject to a 1% LIBOR floor with interest payable quarterly. As of March 31, 2017, $658 million was outstanding. As part of the agreement, a revolving credit facility was established for the amount of $20 million available through, and scheduled to mature on September 18, 2019. In addition to the financing, EGTP entered into various interest rate swaps with an initial notional amount of approximately $505 million at an interest rate of 2.34% to hedge a portion of the interest rate exposure in connection with this financing, as required by the debt covenants. See Note 9 — Derivative Financial Instruments for additional information regarding interest rate swaps. See Note 20 — Subsequent Events for additional information regarding EGTP and the borrowing base committed under the facility was $85 million. The outstanding balance was classified as Long-term debt on Exelon’s and Generation’s Consolidated Balance Sheets.associated nonrecourse debt.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Junior Subordinated Notes
In February 2016, as partJune 2014, Exelon issued $1.15 billion of their semi-annual borrowing base re-determination testing,junior subordinated notes in the RBL lenders notified CEU Holdings thatform of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the RBL borrowing base was decreasedJune 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes may use debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon will receive $1.15 billion upon settlement on June 1, 2017, of the forward equity purchase contract. Exelon currently expects the number of equity shares to $45be issued to range from 26 million to 33 million dependent on Exelon’s stock price at the time of settlement pursuant to the equity unit terms. Until settlement of the equity purchase contract, earnings per share dilution resulting in a “borrowing base deficiency”from the equity units is being determined under the RBL of $23 million. Giventreasury stock method.
For the decline in value of the Upstream assets resulting from lower commodity prices, CEU Holdings chose not to provide the lenders with a formal plan for curing the borrowing base deficiency bythree months ended March 31, 2017 and 2016, as was required bycontract payments of $11 million related to the RBL. The lenders have sent CEU Holdings a noticeContract Payment Obligation were included within Retirements of eventlong-term debt in Exelon’s Consolidated Statements of default and demand for cure. On March 31, 2016, $7 million of the debt was repaid using CEU Holding’s cash, resulting in an outstanding debt balance of $61 million with interest payable monthly at a variable rate equal to LIBOR plus 2.75% and a borrowing base deficiency under the RBL of $16 million. At March 31, 2016, the outstanding debt balance of $61 million was classified within Long-term debt due within one year on Exelon’s and Generation’s Consolidated Balance Sheets.Cash Flows.
On June 16, 2016, CEU Holdings executed a forbearance agreement with the lenders which included terms stipulating roles and responsibilities governing a sales process, approval of the sale of the assets to be at the discretion of the lenders, and a sales timetable, with ultimate execution of the sales agreement expected to occur by December 31, 2016. Upon disposition of the assets and the satisfaction of certain other conditions, CEU Holdings will be released of its obligations regardless of the amount of asset sale proceeds received. The ultimate resolution of this matter has no direct effect on any Exelon or Generation credit facilities or other debt of an Exelon entity. See Note 14 — Debt and Credit Agreements of the Exelon 2015 Form 10-K, Note 5 — Mergers, Acquisitions and Dispositions and Note 6 — Impairment of Long-Lived Assets for additional information.
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, 2016 | Three Months Ended March 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL | ACE | PHI | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||||||||||||||||||||||||||||||
Increase (decrease) due to: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
State income taxes, net of Federal income tax benefit | 3.8 | 2.6 | 7.3 | 2.4 | 5.2 | 5.6 | 5.6 | 5.2 | 6.1 | 0.9 | 1.0 | 4.9 | 0.1 | 5.2 | 4.6 | 5.3 | 5.6 | 4.9 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Qualified nuclear decommissioning trust fund income | 4.0 | 7.8 | — | — | — | — | — | — | — | 3.4 | 7.6 | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Domestic production activities deduction | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Health care reform legislation | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization of investment tax credit, net deferred taxes | (0.9 | ) | (1.6 | ) | (0.6 | ) | (0.1 | ) | (0.2 | ) | (0.1 | ) | — | (0.2 | ) | (0.1 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization of investment tax credit, including deferred taxes on basis difference | (0.4 | ) | (0.7 | ) | (0.2 | ) | (0.1 | ) | (0.1 | ) | (0.1 | ) | (0.3 | ) | (0.4 | ) | (0.2 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Plant basis differences | (3.0 | ) | — | (1.9 | ) | (6.7 | ) | (0.5 | ) | (5.0 | ) | (6.7 | ) | (1.3 | ) | (4.6 | ) | (2.4 | ) | — | (0.2 | ) | (13.2 | ) | (0.9 | ) | (5.8 | ) | (1.9 | ) | (3.4 | ) | (3.8 | ) | ||||||||||||||||||||||||||||||||||||||
Production tax credits and other credits | (2.9 | ) | (5.7 | ) | (0.1 | ) | — | — | — | — | — | — | (0.6 | ) | (1.4 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||
Noncontrolling interests | 0.2 | 0.5 | — | — | — | — | — | — | — | (0.1 | ) | (0.3 | ) | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Statute of limitations expiration | (0.1 | ) | 0.3 | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Penalties | 4.3 | — | 27.2 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Merger expenses | (0.6 | ) | — | — | — | — | (5.7 | ) | (2.3 | ) | (8.6 | ) | (2.9 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Merger expenses(a) | (11.4 | ) | (3.3 | ) | — | — | — | (34.2 | ) | (21.9 | ) | (167.1 | ) | (42.4 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fitzpatrick bargain purchase gain | (6.6 | ) | (14.5 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other | (0.8 | ) | (0.5 | ) | 0.1 | 0.1 | (0.4 | ) | (0.7 | ) | (0.9 | ) | 0.1 | (0.6 | ) | — | (0.1 | ) | — | 0.3 | (0.2 | ) | 0.5 | — | (3.0 | ) | (0.4 | ) | ||||||||||||||||||||||||||||||||||||||||||||
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Effective income tax rate | 39.0 | % | 38.4 | % | 67.0 | % | 30.7 | % | 39.1 | % | 29.1 | % | 30.7 | % | 30.2 | % | 32.9 | % | 17.8 | % | 23.3 | % | 39.5 | % | 22.1 | % | 39.0 | % | 0.0 | % | 16.2 | % | (133.3 | )% | (6.9 | )% | ||||||||||||||||||||||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Three Months Ended September 30, 2015 | ||||||||||||||||||||||||||||||||||||
Predecessor | ||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||||||||||||
Increase (decrease) due to: | ||||||||||||||||||||||||||||||||||||
State income taxes, net of Federal income tax benefit | 2.7 | 2.1 | 5.0 | 1.2 | 5.3 | 6.2 | 4.8 | 7.4 | 5.4 | |||||||||||||||||||||||||||
Qualified nuclear decommissioning trust fund income | (5.4 | ) | (12.5 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||
Domestic production activities deduction | (4.9 | ) | (11.6 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||
Health care reform legislation | — | — | — | — | 0.2 | — | — | — | — | |||||||||||||||||||||||||||
Amortization of investment tax credit, net deferred taxes | (2.3 | ) | (5.2 | ) | (0.3 | ) | (0.1 | ) | (0.2 | ) | (0.2 | ) | (0.1 | ) | (0.6 | ) | (0.3 | ) | ||||||||||||||||||
Plant basis differences | (1.4 | ) | — | (0.1 | ) | (7.0 | ) | (0.6 | ) | (3.7 | ) | (3.5 | ) | (3.5 | ) | (3.1 | ) | |||||||||||||||||||
Production tax credits and other credits | (3.8 | ) | (9.0 | ) | — | — | — | (1.2 | ) | — | — | — | ||||||||||||||||||||||||
Noncontrolling interests | 1.7 | 3.9 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Statute of limitations expiration | (6.4 | ) | (15.2 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||
Other | 1.2 | 0.4 | 0.3 | — | (0.4 | ) | (1.1 | ) | (1.4 | ) | (0.8 | ) | 1.9 | |||||||||||||||||||||||
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Effective income tax rate | 16.4 | % | (12.1 | )% | 39.9 | % | 29.1 | % | 39.3 | % | 35.0 | % | 34.8 | % | 37.5 | % | 38.9 | % | ||||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2016 | March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | ||||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL(a) | ACE(a) | PHI(a) | PHI | |||||||||||||||||||||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||||||||||||||
Increase (decrease) due to: | ||||||||||||||||||||||||||||||||||||||||
State income taxes, net of Federal income tax benefit(b) | 2.5 | 2.6 | 5.4 | 1.3 | 4.8 | 23.0 | 310.5 | 5.5 | 4.4 | 11.9 | ||||||||||||||||||||||||||||||
Qualified nuclear decommissioning trust fund income | 4.8 | 8.8 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Domestic production activities deduction | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Health care reform legislation | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Amortization of investment tax credit, including deferred taxes on basis difference | (1.3 | ) | (2.0 | ) | (0.3 | ) | (0.1 | ) | (0.2 | ) | (0.2 | ) | (17.9 | ) | 0.5 | 0.5 | (0.9 | ) | ||||||||||||||||||||||
Plant basis differences | (4.5 | ) | — | (0.6 | ) | (8.8 | ) | (3.3 | ) | (29.0 | ) | (98.6 | ) | 7.8 | 17.5 | (13.5 | ) | |||||||||||||||||||||||
Production tax credits and other credits | (4.1 | ) | (7.6 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
Noncontrolling interests | 0.5 | 0.9 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Statute of limitations expiration | (0.5 | ) | (1.7 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||
Penalties | 2.3 | — | 5.6 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||
Merger expenses | 6.2 | — | — | — | — | 36.7 | 635.9 | (35.4 | ) | (49.8 | ) | 11.1 | ||||||||||||||||||||||||||||
Other(c) | (1.8 | ) | (2.1 | ) | — | (1.5 | ) | — | (2.5 | ) | 35.1 | 0.4 | 1.4 | 3.6 | ||||||||||||||||||||||||||
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Effective income tax rate | 39.1 | % | 33.9 | % | 45.1 | %�� | 25.9 | % | 36.3 | % | 63.0 | % | 900.0 | % | 13.8 | % | 9.0 | % | 47.2 | % | ||||||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Nine Months Ended September 30, 2015 | Successor |
| Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Predecessor | Three Months Ended March 31, 2016 | March 24, 2016 to March 31, 2016 |
| January 1, 2016 to March 23, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | Exelon | Generation | ComEd | PECO | BGE | Pepco(b) | DPL(b) | ACE(b) | PHI(b) | PHI | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||||||||||||||||||||||||||||||||||||
Increase (decrease) due to: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
State income taxes, net of Federal income tax benefit | 3.1 | 2.8 | 5.2 | 1.2 | 5.3 | 7.1 | 4.6 | 6.1 | 5.5 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
State income taxes, net of Federal income tax | (1.1 | ) | 3.7 | 5.1 | 1.0 | 5.2 | (2.5 | ) | (2.7 | ) | 5.9 | 5.4 | 11.9 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Qualified nuclear decommissioning trust fund income | (0.9 | ) | (1.6 | ) | — | — | — | — | — | — | — | 5.6 | 4.2 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Domestic production activities deduction | (2.8 | ) | (4.9 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Health care reform legislation | — | — | — | — | 0.2 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization of investment tax credit, including deferred taxes on basis difference | (1.2 | ) | (1.9 | ) | (0.3 | ) | (0.1 | ) | (0.1 | ) | (0.3 | ) | (0.1 | ) | (0.4 | ) | (0.5 | ) | (1.6 | ) | (1.0 | ) | (0.3 | ) | (0.1 | ) | (0.1 | ) | — | 0.1 | 0.2 | — | (0.9 | ) | ||||||||||||||||||||||||||||||||||||||||||||||
Plant basis differences | (1.2 | ) | — | (0.1 | ) | (7.3 | ) | (0.4 | ) | (5.0 | ) | (6.2 | ) | (2.0 | ) | (2.5 | ) | (5.5 | ) | — | (0.1 | ) | (9.3 | ) | (0.6 | ) | 2.8 | 0.7 | 0.6 | — | (13.5 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
Production tax credits and other credits | (2.2 | ) | (3.8 | ) | — | — | — | (1.9 | ) | — | — | — | (5.1 | ) | (3.9 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncontrolling interests | — | 0.1 | — | — | — | — | — | — | — | 0.5 | 0.3 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Statute of limitations expiration | (1.6 | ) | (2.9 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Merger expenses | 33.6 | — | — | — | — | (16.5 | ) | (22.1 | ) | (17.0 | ) | (15.1 | ) | 11.1 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other | 0.9 | 0.6 | 0.2 | 0.2 | (0.1 | ) | (0.1 | ) | (0.7 | ) | (0.5 | ) | 0.8 | (2.0 | ) | (1.6 | ) | 0.4 | (0.9 | ) | — | — | 0.1 | 0.1 | 0.2 | 3.6 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Effective income tax rate | 29.1 | % | 23.4 | % | 40.0 | % | 29.0 | % | 39.9 | % | 34.8 | % | 32.6 | % | 38.2 | % | 38.3 | % | 59.4 | % | 36.7 | % | 40.1 | % | 25.7 | % | 39.5 | % | 18.8 | % | 11.1 | % | 24.8 | % | 25.5 | % | 47.2 | % | ||||||||||||||||||||||||||||||||||||||||||
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(a) | Includes a remeasurement of uncertain federal and state income tax positions, see below. |
(b) | Pepco, DPL and ACE recognized a loss before income taxes for the |
Includes a remeasurement of uncertain state income tax positions for Pepco and DPL. |
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Accounting for Uncertainty in Income Taxes
The Registrants have the following unrecognized tax benefits as of September 30, 2016March 31, 2017 and December 31, 2015:2016:
Successor | ||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||
September 30, 2016 | $ | 937 | $ | 516 | $ | (12 | ) | $ | — | $ | 120 | $ | 157 | $ | 79 | $ | 34 | $ | 22 | |||||||||||||||||
Predecessor | ||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||
December 31, 2015 | $ | 1,101 | $ | 534 | $ | 142 | $ | — | $ | 120 | $ | 22 | $ | 8 | $ | 3 | $ | — |
Successor | ||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||
March 31, 2017 | $ | 769 | $ | 470 | $ | (12 | ) | $ | — | $ | 120 | $ | 112 | $ | 59 | $ | 21 | $ | — |
Successor | ||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||
December 31, 2016 | $ | 916 | $ | 490 | $ | (12 | ) | $ | — | $ | 120 | $ | 172 | $ | 80 | $ | 37 | $ | 22 |
Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation in 2012 and ComEd’s unrecognized tax benefits changed by $328 million and $154 million, respectively, as of September 30, 2016PHI in 2016. In the first quarter 2017, as a resultpart of its examination of Exelon’s return, the lease termination onIRS National Office issued guidance concurring with Exelon’s position that the like-kind exchange position discussed below. In addition, asmerger commitments were deductible. As a result, of the merger, an assessment and remeasurement of certain federal and state uncertain income tax positions resulted in an increase in unrecognized tax benefits at Exelon, Generation, PHI, Pepco, DPL, and ACE of $164decreased their liability for unrecognized tax benefits by $146 million, $135$19 million, $71$59 million, $31$21 million, $16 million, and $22 million, respectively.respectively, as of March 31, 2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
Like-Kind Exchange
As of March 31, 2017, Exelon and ComEd have approximately $76 million and $(12) million, respectively, of unrecognized state income tax benefits that could significantly decrease and increase within the 12 months after the reporting date due to a final resolution of the like-kind exchange litigation described below. The recognition of these unrecognized tax benefits would decrease Exelon’s effective tax rate and increase ComEd’s effective tax rate.
Settlement of Income Tax Audits and Litigation
As of September 30, 2016,March 31, 2017, Exelon, Generation, BGE, PHI, Pepco, and DPL have approximately $251$257 million, $52$57 million, $120 million, $79$80 million, $59 million, and $20$21 million of unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits and potential settlements. Of the above unrecognized tax benefits, Exelon and Generation have $52$50 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefits related to BGE, DPL, and a portion of Pepco, if recognized, may be included in future regulated base rates and that portion would have no impact to the effective tax rate.
Other Income Tax Matters
Like-Kind Exchange (Exelon and ComEd)
Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities.
The IRS disagreed with this position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999. Exelon was unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS asserted that the Exelon purchase and leaseback transaction was substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities did not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS also asserted a penalty of approximately $90 million for a substantial understatement of tax.
In accordance with applicable accounting standards, Exelon was required to assess whether it wasmore-likely-than-not that to prevail in litigation. In light of the outcome of another case involving a listed transaction and Exelon’s determination that settlement was unlikely, Exelon concluded that subsequent to December 31, 2012, it was no longer more-likely-than-not that its position would be sustained. As a result, in the first quarter of 2013 Exelon recorded a non-cash charge to earnings of approximately $265 million, which represented the amount of interest expense (after-tax) and incremental state income tax expense for periods through March 31, 2013, that would be payable in the event that Exelon is unsuccessful in litigation. Of this amount, approximately $172 million was recorded at ComEd. Exelon has agreed to hold ComEd harmless from any unfavorable impacts on ComEd’s equity of the after-tax interest or penalty amounts. As a result, ComEd recorded on its consolidated balance sheet as of March 31, 2013, a $172 million receivable and non-cash equity contributions from Exelon. Based on applicable case law and the facts of the transaction, Exelon did not believe it was likely a penalty would be assessed. Accordingly, no charge was recorded for the penalty asserted nor for after-tax interest that could be due on the asserted penalty.
On September 30, 2013, the IRS issued a notice of deficiency to Exelon for the like-kind exchange position. Exelon filed a petition on December 13, 2013 to initiate litigation in the United States Tax Court and the trial took place in August of 2015. Exelon was not required to remit any part of the asserted tax or penalty in order to litigate the issue.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
On September 19, 2016, the Tax Court rejected Exelon’s position in the case and ruled that Exelon was not entitled to defer gain on the transaction. In addition, contrary to Exelon’s evaluation that the penalty was unwarranted, the Tax Court ruled that Exelon is liable for the penalty and interest due on the asserted penalty. In early 2017, Exelon expects to timely appeal this decision to the U.S. Court of Appeals for the Seventh Circuit.Circuit in 2017.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
In the first quarter of 2013, Exelon concluded that it was no longer more likely than not that the like-kind exchange position would be sustained and recorded charges to earnings representing the amount of interest expense(after-tax) and incremental state income tax expense that would be payable in the event Exelon is unsuccessful in litigation. Prior to the Tax Court’s decision, however, Exelon did not believe it was likely a penalty would be assessed based on applicable case law and the facts of the transaction. As a result, no charge had been recorded for the penalty or forafter-tax interest on the penalty. While it has strong arguments on appeal with respect to both the merits and the penalty, Exelon has determined that, pursuant to accounting standards, it is no longer more-likely-than-notmore likely than not to avoid ultimate imposition of the penalty. As a result, in the third quarter of 2016, Exelon and ComEd recorded a charge to earnings for theof approximately $106 million and $86 million, respectively, of penalty and the after-tax interest due on the asserted penalty of approximately $200$94 million of which approximately $150and $64 million, was recorded at ComEd.respectively, ofafter-tax interest. Exelon and ComEd recorded the penalty andpre-tax interest due on the asserted penalty to Other, net and Interest expense, net, respectively, on their Consolidated Statements of Operations. Consistent with Exelon’s agreement to continue to hold ComEd harmless from any unfavorable impact on its equity, ComEd recorded on its consolidated balance sheetConsolidated Balance Sheets as of September 30, 2016, a $150 million receivable andnon-cash equity contributions from Exelon. In addition, while further adjustments may be required, Exelon currently estimates that its income tax expense may decrease by as much as $50 million and ComEd’s income tax expense may increase by as much as $20 million resulting from the IRS’s completion of its calculation of tax, penalties, and interest in the second quarter of 2017.
In order to appeal the decision, Exelon is required to pay the tax, penalties and interest at the time Exelon files its appeal (expected earlyin the third quarter of 2017). While the final calculation of tax, penalties and interest has not yet been finalized by the IRS, Exelon estimates that a payment of approximately $1.4$1.3 billion related to the like-kind exchange will be due, including $300 million from ComEd, in the firstthird quarter of 2017. While Exelon will receive a tax benefit of $400approximately $350 million associated with the deduction for the interest, Exelon currently has a net operating loss carryforward and thus does not expect to realize the cash benefit until 2018. After taking into account these interest deduction tax benefits, the total estimated net cash outflow for the like-kind exchange is $1 billion,approximately $950 million, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts ofafter-tax interest or penalty amounts on ComEd’s equity. Upon a final appellate decision, which could take up to several years, Exelon expects to receive approximately $80 million related to final interest computations.
Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. The remaining amount will be paid in the third quarter of 2017 at the time Exelon files its appeal of the Tax Court decision. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings. The deposit is reflected as a current asset and the related liabilities for the tax, penalty, and interest are included on Exelon’s balance sheet as current obligations.
As of September 30, 2016,March 31, 2017, ComEd has a total receivable from Exelon pursuant to the hold harmless agreement of $345 million, which is included in Current Receivables from Affiliates on ComEd’s Consolidated Balance Sheet. Under the agreement, Exelon will settle this receivable with ComEd no later than the time that the payments related to the like-kind exchange are due to the IRS, currently anticipated in firstthe third quarter of 2017. Exelon will not seek recovery from ComEd customers for any interest or penalty payment amounts associated with the like-kind exchange tax position.
As previously disclosed, in the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electric generation properties in exchange for a net early termination amount of $335 million. On March 31,In the first quarter of 2016, Exelon entered into an agreement to terminateterminated its interests in the remaining two municipal-owned electric generation properties in exchange for $360 million.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Long-Term Marginal State Income Tax ApportionmentRate (Exelon, Generation and PHI)
Exelon, Generation and PHI periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of their respective deferred state income taxes. Events that may require Exelon, Generation and PHI to update their long-term state tax apportionment include significant changes in tax law and/or significant operational changes, suchchanges. Exelon and PHI’s long-term marginal state income tax rate was revised in the first quarter of 2017 as the merger with PHI. As a result of the merger, Exelon and Generation reevaluated their long-term state tax apportionment for all states where they havea statutory rate change pursuant to Exelon’s marginal state income tax obligations, which include Delaware, Illinois, Maryland, New Jersey, Pennsylvania, and Washington D.C., as well as other states. The total effect of revising the long-term state tax apportionment
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
resultedrate policy, resulting in the recording of a deferred state tax benefit in the amountfor Exelon of $1 million and a state tax expense of $6$21 million, net of tax, for Exelontax.
12. Nuclear Decommissioning (Exelon and Generation, respectively. Further, Exelon and PHI recorded deferred state tax liabilities of $59 million and $8 million, net of tax, respectively, as part of purchase accounting during the first quarter of 2016.
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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 aunit-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 following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 20152016 to September 30, 2016:March 31, 2017:
Nuclear decommissioning ARO at December 31, 2015(a) | $ | 8,246 | ||
Accretion expense | 325 | |||
Net increase due to changes in, and timing of, estimated cash flows | 444 | |||
Costs incurred to decommission retired plants | (6 | ) | ||
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Nuclear decommissioning ARO at September 30, 2016(a) | $ | 9,009 | ||
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Nuclear decommissioning ARO at December 31, 2016(a) | $ | 8,734 | ||
Acquisition of FitzPatrick | 417 | |||
Accretion expense | 109 | |||
Costs incurred to decommission retired plants | (1 | ) | ||
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| |||
Nuclear decommissioning ARO at March 31, 2017(a)(b) | $ | 9,259 | ||
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(a) | Includes |
(b) | Includes the fair value of the FitzPatrick ARO liability as of March 31, 2017, the date of the acquisition. See Note 4 —Mergers, Acquisitions and Dispositions. |
During the ninethree months ended September 30, 2016,March 31, 2017, Generation’s nuclear ARO increased by approximately $763 million, reflecting impacts$525 million. The increase is largely driven by the acquisition of FitzPatrick. The fair value of FitzPatrick’s assets and liabilities, including the ARO, updates completed during the firstwas determined based on significant estimates and second quarters of 2016 to reflect changesassumptions that are judgmental in amounts and timing of estimated decommissioning cash flows and impacts of year-to-date accretionnature. The fair value of the ARO liability due to the passage of time.
In 2016, the ARO liability increased by $444 million primarily driven byis considered an increase of $384 million associated with the June 2, 2016 announcement to early retire the Clintoninitial estimate and Quad Cities nuclear units on June 1, 2017 and June 1, 2018, respectively, as well as an increase of $60 million primarily due to an increase in the estimated costs to decommission the Oyster Creek nuclear unit as a result of the completion of an updated decommissioning cost study. Refer to Note 7 — Early Nuclear Plant Retirements for additional information regarding the announced early retirements of Clinton and Quad Cities. The increase in the ARO liability for Clinton and Quad Cities incorporates the early shutdown dates (including fleet-wide impacts of spent nuclear fuel removal and storage costs), increases in the assumed probabilities of longer term decommissioning scenarios, and reflects an increase in the estimated costs to decommission based on updated decommissioning cost studies reflecting the early retirement of these units.
The financial statement impact related to the increase in the ARO liability due to the changes in, and timing of, estimated cash flows resulted in a corresponding increase in Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. The majority of the increase in cost will be amortized overupdated with inputs from a third party engineering firm with corresponding adjustments recorded by the remaining useful livesend of 2017. For additional details on the Clinton, Quad Citiesacquisition of FitzPatrick, see Note 4 — Mergers, Acquisitions and Oyster Creek nuclear plants, which are set to retire in 2017, 2018 and 2019, respectively.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Dispositions.
Nuclear Decommissioning Trust Fund Investments
NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The NDT funds associated with Generation’s nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment (NDCA) with the PAPUC proposing an annual recovery from customers of approximately $4 million which, if approved by the PAPUC, will be effective January 1, 2018. This amount reflects a decrease from the current approved annual collection of approximately $24 million primarily due to the removal of the collections for Limerick Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. See Note 16 — Asset Retirement Obligations of Exelon’s 2016 Form10-K, for information regarding the amount collected from PECO ratepayers for decommissioning costs.
At September 30, 2016March 31, 2017 and December 31, 2015,2016, Exelon and Generation had NDT fund investments totaling $11,076$12,362 million and $10,342$11,061 million, respectively. The increase is primarily driven by the acquisition of FitzPatrick.
The following table provides unrealized gains on NDT funds for the three and nine months ended September 30, 2016March 31, 2017 and 2015:2016:
Exelon and Generation | Exelon and Generation | |||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Net unrealized gains (losses) on decommissioning trust funds —Regulatory Agreement Units(a) | $ | 155 | $ | (301 | ) | $ | 286 | $ | (385 | ) | ||||||
Net unrealized gains (losses) on decommissioning trust funds —Non-Regulatory Agreement Units(b)(c) | 116 | (218 | ) | 216 | (274 | ) |
Exelon and Generation | ||||||||
Three Months Ended March 31, | ||||||||
2017 | 2016 | |||||||
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units(a) | $ | 222 | $ | 79 | ||||
Net unrealized gains on decommissioning trust funds —Non-Regulatory Agreement Units(b)(c) | 166 | 52 |
(a) | Net unrealized gains related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets. |
(b) | Excludes |
(c) | Net unrealized gains related to Generation’s NDT funds withNon-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. |
Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.
Refer to Note 3 — Regulatory Matters and Note 2627 — Related Party Transactions of the Exelon 20152016 Form10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Zion Station Decommissioning
On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, under which ZionSolutions has assumed responsibility for completing certain decommissioning activities at Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 16 — Asset Retirement Obligations of the Exelon 20152016 Form10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction.
ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to Pledged assets for Zion
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Station decommissioning within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, are recorded as a change in the Payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for the SNF. Following ZionSolutions’ completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $87$112 million which is included within the nuclear decommissioning ARO at September 30, 2016.March 31, 2017. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at September 30, 2016March 31, 2017 and December 31, 2015:2016:
Exelon and Generation | Exelon and Generation | |||||||||||||||
September 30, 2016 | December 31, 2015 | March 31, 2017 | December 31, 2016 | |||||||||||||
Carrying value of Zion Station pledged assets | $ | 135 | $ | 206 | $ | 95 | $ | 113 | ||||||||
Payable to Zion Solutions(a) | 124 | 189 | 88 | 104 | ||||||||||||
Current portion of payable to Zion Solutions(b) | 91 | 99 | 85 | 90 | ||||||||||||
Cumulative withdrawals by Zion Solutions to pay decommissioning costs(c) | 855 | 786 | 895 | 878 |
(a) | Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized. |
(b) | Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets. |
(c) | Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings. |
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 March 31, 2015. This30, 2017 for all units except for Zion Station which is included in a separate report reflects the status of decommissioning funding assurance as of December 31, 2014. Due to increased cost estimates received in the second half of 2014, Braidwood Units 1 and 2, and Byron Unit 2 did not meet the NRC’s minimum funding assurance criteria as of December 31, 2014. NRC guidance provides licensees with two years or by the time of submitting the next biennial report (on or before March 31, 2017) to resolve funding assurance shortfalls. On February 4, 2016, Generation submitted to the NRC an updated decommissioning funding status report for Braidwood Units 1 and 2, and Byron Unit 2. This updated report reflected the recently approved license renewals for these units, and showed that the shortfall identified in the March 31, 2015 report has now been resolved and that Generation has provided adequate decommissioning funding assurance for each unit.
On March 31, 2016, Generation submitted its NRC required annual decommissioning funding status report as of December 31, 2015 for reactors that have been shut down or are within five years of shut down except forby EnergySolutions
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Zion Station which is included in a separate report to the NRC submitted by EnergySolutions (see(see Zion Station Decommissioning above). As of December 31, 2015, Generation providedThe status report demonstrated adequate decommissioning funding assurance for all of its reactors that have been shut down or are within five years of shut downunits except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund in addition to collections from PECO ratepayers. As discussed in Note 16 — Asset Retirement Obligations of Exelon’s 2015 Form 10-K,under Nuclear Decommissioning Trust Fund Investments above, the amount collected from PECO ratepayers will behas been adjusted in the nextMarch 31, 2017 filing to the PAPUC with new rateswhich, if approved by the PAPUC, will be effective January 1, 2018.
Generation will file its next decommissioning funding status report with the NRC by March 31, 2017. This report will reflect the status of decommissioning funding assurance as of December 31, 2016 and will reflect the impacts of the announced early retirements of Clinton and Quad Cities. A shortfall could require Exelon to post parental guarantees for Generation’s share of the funding assurance. However, the amount of any required guarantees will ultimately depend on the decommissioning approach adopted at each site, the associated level of costs, and the decommissioning trust fund investment performance going forward.
Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all employees.
Effective March 31, 2017, in connection with the acquisition of FitzPatrick, Exelon established a new qualified pension plan and a new other postretirement employee benefit plan, and recorded benefit plan obligations of $38 million and $11 million, respectively. Refer to Note 4 — Mergers, Acquisitions and Dispositions for additional discussion of the acquisition of FitzPatrick.
Effective March 23, 2016, Exelon became the sponsor of all of PHI’s defined benefit pension and other postretirement benefit plans, and assumed PHI’s benefit plan obligations and related assets. As a result, PHI’s benefit plan net obligation and related regulatory assets were transferred to Exelon. The legacy PHI pension and other postretirement benefit plans were initially remeasured on February 29, 2016 as a result of the short time between the merger close and the end of the first quarter of 2016, using current assumptions, including the discount rate. Exelon updated these amounts in June 2016 to reflect assumptions at March 31, 2016. The updated valuation resulted in a $25 million reduction in the net obligation.
Defined Benefit Pension and Other Postretirement Benefits
During the first quarter of 2016,2017, Exelon received an updated valuation of its legacy pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2016.2017. This valuation resulted in an increase to the pension obligation of $35$92 million and a decreasean increase to the other postretirement benefit obligation of $8$57 million. Additionally, accumulated other comprehensive loss increased by approximately $2$59 million (after tax), regulatory assets increased by approximately $27$57 million and regulatory liabilities increased by approximately $3$4 million.
The majority of the 20162017 pension benefit cost for legacy Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.29%4.04%. The majority of the 20162017 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.71%6.58% for funded plans and a discount rate of 4.29%4.04%.
The 2016 pension benefit costs for the legacy PHI plans are calculated using an expected long-term rate of return on plan assets of 6.50% and a discount rate of 3.96% for the majority of the pension plans. The 2016 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.75% and a discount rate of 3.80%.
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, 2016 and 2015.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Pension Benefits Three Months Ended September 30, | Other Postretirement Benefits Three Months Ended September 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Components of net periodic benefit cost: | ||||||||||||||||
Service cost | $ | 92 | $ | 82 | $ | 27 | $ | 30 | ||||||||
Interest cost | 215 | 178 | 47 | 42 | ||||||||||||
Expected return on assets | (293 | ) | (257 | ) | (42 | ) | (38 | ) | ||||||||
Amortization of: | ||||||||||||||||
Prior service cost (benefit) | 3 | 3 | (48 | ) | (43 | ) | ||||||||||
Actuarial loss | 142 | 142 | 18 | 20 | ||||||||||||
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Net periodic benefit cost | $ | 159 | $ | 148 | $ | 2 | $ | 11 | ||||||||
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A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following tables present the components of Exelon’s net periodic benefit costs, prior to capitalization, for the three months ended March 31, 2017 and 2016 and PHI’s net periodic benefit costs, prior to capitalization, for the predecessor period of January 1, 2016 to March 23, 2016.
Pension Benefits Nine Months Ended September 30, | Other Postretirement Benefits Nine Months Ended September 30, | Pension Benefits Three Months Ended March 31, | Other Postretirement Benefits Three Months Ended March 31, | |||||||||||||||||||||||||||||
2016(a) | 2015 | 2016(a) | 2015 | 2017 | 2016(a) | 2017 | 2016(a) | |||||||||||||||||||||||||
Components of net periodic benefit cost: | ||||||||||||||||||||||||||||||||
Service cost | $ | 262 | $ | 245 | $ | 80 | $ | 89 | $ | 95 | $ | 78 | $ | 26 | $ | 26 | ||||||||||||||||
Interest cost | 616 | 533 | 138 | 125 | 210 | 190 | 45 | 43 | ||||||||||||||||||||||||
Expected return on assets | (847 | ) | (770 | ) | (121 | ) | (113 | ) | (299 | ) | (263 | ) | (41 | ) | (38 | ) | ||||||||||||||||
Amortization of: | ||||||||||||||||||||||||||||||||
Prior service cost (benefit) | 10 | 10 | (138 | ) | (130 | ) | — | 3 | (47 | ) | (44 | ) | ||||||||||||||||||||
Actuarial loss | 411 | 427 | 47 | 60 | 152 | 127 | 16 | 14 | ||||||||||||||||||||||||
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Net periodic benefit cost | $ | 452 | $ | 445 | $ | 6 | $ | 31 | $ | 158 | $ | 135 | $ | (1 | ) | $ | 1 | |||||||||||||||
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(a) | PHI net periodic benefit costs for the period prior to the merger are not included in the table above. |
Predecessor | Predecessor | |||||||||||||||||||||||||||||||
PHI | PHI | |||||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||||
January 1, 2016 to March 23, 2016 | Three Months Ended September 30, 2015 | Nine Months Ended September 30, 2015 | January 1, 2016 to March 23, 2016 | Three Months Ended September 30, 2015 | Nine Months Ended September 30, 2015 | January 1, 2016 to March 23, 2016 | January 1, 2016 to March 23, 2016 | |||||||||||||||||||||||||
Components of net periodic benefit cost: | ||||||||||||||||||||||||||||||||
Service cost | $ | 12 | $ | 15 | $ | 43 | $ | 1 | $ | 2 | $ | 5 | $ | 12 | $ | 1 | ||||||||||||||||
Interest cost | 26 | 28 | 82 | 6 | 6 | 18 | 26 | 6 | ||||||||||||||||||||||||
Expected return on assets | (30 | ) | (35 | ) | (105 | ) | (5 | ) | (6 | ) | (17 | ) | (30 | ) | (5 | ) | ||||||||||||||||
Amortization of: | ||||||||||||||||||||||||||||||||
Prior service cost (benefit) | — | — | 1 | (3 | ) | (3 | ) | (9 | ) | — | (3 | ) | ||||||||||||||||||||
Actuarial loss | 14 | 16 | 49 | 2 | 2 | 6 | 14 | 2 | ||||||||||||||||||||||||
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Net periodic benefit cost | $ | 22 | $ | 24 | $ | 70 | $ | 1 | $ | 1 | $ | 3 | $ | 22 | $ | 1 | ||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The amounts below represent Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s, ACE’s, BSC’s and PHISCO’s allocated portion of the pension and postretirement benefit plan costs, which were included in Property, plant and equipment within the respective Consolidated Balance Sheets and Operating and maintenance expense within the Consolidated Statement of Operations and Comprehensive Income during the three and nine months ended September 30,March 31, 2017 and 2016 and 2015.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)PHI’s for the predecessor and successor periods of January 1, 2016 to March 23, 2016 and March 24, 2016 to March 31, 2016, respectively.
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
Pension and Other Postretirement Benefit Costs | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||
Exelon | $ | 161 | $ | 159 | $ | 458 | $ | 476 | $ | 157 | $ | 136 | ||||||||||||
Generation | 54 | 67 | 163 | 200 | 54 | 54 | ||||||||||||||||||
ComEd | 41 | 52 | 124 | 155 | 44 | 41 | ||||||||||||||||||
PECO | 8 | 10 | 25 | 29 | 7 | 8 | ||||||||||||||||||
BGE | 17 | 16 | 51 | 49 | 16 | 16 | ||||||||||||||||||
BSC(a) | 13 | 14 | 37 | 43 | 12 | 14 | ||||||||||||||||||
Pepco(b) | 8 | 7 | 24 | 22 | 7 | 8 | ||||||||||||||||||
DPL(b) | 4 | 3 | 13 | 11 | 3 | 5 | ||||||||||||||||||
ACE(b) | 4 | 3 | 11 | 11 | 3 | 4 | ||||||||||||||||||
PHISCO(a)(b) | 12 | 12 | 33 | 29 | 11 | 9 |
Successor | Predecessor | Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||
Pension and Other Postretirement Benefit Costs | Three Months Ended September 30, 2016 | Three Months Ended September 30, 2015 | March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | Nine Months Ended September 30, 2015 | March 24, 2016 to March 31, 2016 | January 1, 2016 to March 23, 2016 | |||||||||||||||||||||||||
PHI | $ | 28 | $ | 25 | $ | 58 | $ | 23 | $ | 73 | $ | 3 | $ | 23 |
(a) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above. |
(b) | Pepco’s, DPL’s, ACE’s and PHISCO’s pension and postretirement benefit costs for the |
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 theirpre-tax and/orafter-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, 2016March 31, 2017 and 2015:2016:
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
Savings Plan Matching Contributions | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||
Exelon | $ | 51 | $ | 51 | $ | 107 | $ | 111 | $ | 30 | $ | 26 | ||||||||||||
Generation | 31 | 27 | 56 | 60 | 14 | 12 | ||||||||||||||||||
ComEd | 10 | 10 | 23 | 23 | 7 | 6 | ||||||||||||||||||
PECO | 3 | 3 | 7 | 7 | 2 | 2 | ||||||||||||||||||
BGE | 2 | 5 | 5 | 10 | 2 | 1 | ||||||||||||||||||
BSC(a) | 2 | 6 | 9 | 11 | 2 | 5 | ||||||||||||||||||
Pepco(b) | — | — | 2 | 2 | 1 | 1 | ||||||||||||||||||
DPL(b) | 1 | 1 | 2 | 2 | 1 | 1 | ||||||||||||||||||
ACE(b) | — | — | 1 | 1 | ||||||||||||||||||||
PHISCO(a)(b) | 2 | 2 | 5 | 5 | 1 | 1 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Successor | Predecessor | Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||
Savings Plan Matching Contributions | Three Months Ended September 30, 2016 | Three Months Ended September 30, 2015 | March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | Nine Months Ended September 30, 2015 | March 24, 2016 to March 31, 2016 | January 1, 2016 to March 23, 2016 | |||||||||||||||||||||||||
PHI | $ | 3 | $ | 3 | $ | 7 | $ | 3 | $ | 10 | $ | — | $ | 3 |
(a) | These amounts primarily represent amounts billed to Exelon and PHI’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO, BGE, Pepco and DPL amounts above. |
(b) | Pepco’s, DPL’s and PHISCO’s matching contributions for the |
14. Severance (All Registrants)
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The Registrants have an ongoing severance plan under which, in general, the longer an employee worked prior to termination the greater the amount of severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“(“one-time termination benefits”), the Registrants measure the obligation and record the expense at fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.
Ongoing Severance Plans
The Registrants provide severance and health and welfare benefits under Exelon’s ongoing severance benefit plans to terminated employees in the normal course of business. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated.
For the three and nine months ended September 30,March 31, 2017 and 2016, and 2015, Exelon, Generation, ComEd and PHIComEd recorded the following severance costs (benefits) associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income.
Successor | ||||||||||||||||
Exelon | Generation(a) | ComEd(a) | PHI | |||||||||||||
Three Months Ended | ||||||||||||||||
September 30, 2016 | $ | 8 | $ | 7 | $ | — | $ | 1 | ||||||||
September 30, 2015 | (3 | ) | (3 | ) | — | — | ||||||||||
Nine Months Ended | ||||||||||||||||
September 30, 2016 | $ | 12 | $ | 10 | $ | 1 | $ | 1 | ||||||||
September 30, 2015 | 18 | 17 | 1 | — |
Exelon | Generation(a) | ComEd(a) | ||||||||||
Three Months Ended | ||||||||||||
March 31, 2017 | $ | 4 | $ | 3 | $ | 1 | ||||||
March 31, 2016 | 2 | 2 | — |
(a) | The amounts above for Generation include |
Early Plant Retirement-Related Severance
As a result of the Clinton and Quad Cities plant retirement decision, Exelon and Generation will incur certain employee-related costs, including severance benefit costs. Severance benefits will be provided to
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
impacted union and non-union employees, to the extent that those employees are not redeployed to other locations. The final amount of severance cost will ultimately depend on the specific employees severed.
For the three and nine months ended September 30, 2016, the Registrants recorded the following severance costs (benefits) related to the early plant retirements within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:
Exelon | Generation(a) | |||||||
Three Months Ended | ||||||||
September 30, 2016 | $ | (2 | ) | $ | (2 | ) | ||
Nine Months Ended | ||||||||
September 30, 2016 | $ | 44 | $ | 44 |
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Cost Management Program-Related Severance
In August 2015, Exelon announced a cost management program focused on cost savings at BSC and Generation, including the elimination of approximately 500 positions. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity. Exelon expects that approximately 250 corporate support positions in BSC and approximately 250 positions located throughout Generation will be eliminated.
Upon Senior Management approval of the cost management targets and initiatives in the first quarter of 2016, Exelon recorded severance benefit costs of $17 million associated with the anticipated position reductions. Additional severance benefit costs recorded in the third quarter were $1 million for Generation and Exelon. The final amount of the charge will ultimately depend on the specific employees severed.
For the ninethree months ended September 30,March 31, 2017 and 2016, the Registrants recorded the following severance costs related to the cost management program within Operating and maintenance expense in their Consolidated
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Nine Months Ended September 30, 2016 | ||||||||||||||||||||
Severance benefits(a) | $ | 18 | $ | 13 | $ | 3 | $ | 1 | $ | 1 |
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Three Months Ended | ||||||||||||||||||||
March 31, 2017(a) | $ | (1 | ) | $ | (1 | ) | $ | — | $ | — | $ | — | ||||||||
March 31, 2016(b) | $ | 17 | $ | 12 | $ | 3 | $ | 1 | $ | 1 |
(a) | Amounts billed by BSC through intercompany allocations for the three months ended March 31, 2017 were immaterial. |
(b) | The amounts above for Generation, ComEd, PECO and BGE include $7 million, $3 million, $1 million and $1 million, respectively, for amounts billed by BSC through intercompany allocations for the |
Severance Costs Related to the PHI Merger
Upon closing the PHI Merger, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. Cash payments under the plan began in May 2016 and will continue through 2020.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
For the three months ended September 30, 2016,March 31, 2017, the PHI merger severance costs were immaterial. For the ninethree months ended September 30,March 31, 2016, the Registrants recorded the following severance costs associated with the identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:
Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco(b) | DPL(c) | ACE | Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Severance benefits(a) | $ | 55 | $ | 9 | $ | 2 | $ | 1 | $ | 1 | $ | 42 | $ | 20 | $ | 12 | $ | 10 | $ | 52 | $ | 10 | $ | 2 | $ | 1 | $ | 1 | $ | 37 | $ | 18 | $ | 11 | $ | 8 |
(a) | The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $9 million, $2 million, $1 million, $1 million, $18 million, $11 million and $8 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations |
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Severance Liability
Amounts included in the table below represent the severance liability recorded for the severance plans above for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:
Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Severance Liability | Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2015 | $ | 35 | $ | 23 | $ | 3 | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2016 | $ | 88 | $ | 36 | $ | 3 | $ | — | $ | — | $ | 29 | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Severance charges | 136 | 63 | 1 | — | — | 53 | 1 | 1 | — | 3 | 1 | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Payments | (39 | ) | (7 | ) | (1 | ) | — | (1 | ) | (25 | ) | (1 | ) | (1 | ) | — | (10 | ) | (3 | ) | — | — | — | (5 | ) | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
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Balance at September 30, 2016 | $ | 132 | $ | 79 | $ | 3 | $ | — | $ | — | $ | 28 | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance at March 31, 2017 | $ | 81 | $ | 34 | $ | 3 | $ | — | $ | — | $ | 24 | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
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(a) | Includes salary continuance and health and welfare severance benefits. |
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
15. Changes in Accumulated Other Comprehensive Income (Exelon, Generation, PECO and PHI) |
The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the ninethree months ended September 30, 2016March 31, 2017 and 2015:2016:
Nine Months Ended September 30, 2016 | Gains and (losses) on Cash Flow Hedges | Unrealized Gains and (losses) on Marketable Securities | Pension and Non-Pension Postretirement Benefit Plan Items | Foreign Currency Items | AOCI of Equity Investments | Total | ||||||||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, 2017 | Gains and (losses) on Cash Flow Hedges | Unrealized Gains and (losses) on Marketable Securities | Pension and Non-Pension Postretirement Benefit Plan Items | Foreign Currency Items | AOCI of Equity Investments | Total | ||||||||||||||||||||||||||||||||||||||||||
Exelon(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Beginning balance | $ | (19 | ) | $ | 3 | $ | (2,565 | ) | $ | (40 | ) | $ | (3 | ) | $ | (2,624 | ) | $ | (17 | ) | $ | 4 | $ | (2,610 | ) | $ | (30 | ) | $ | (7 | ) | $ | (2,660 | ) | ||||||||||||||
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OCI before reclassifications | (1 | ) | — | (2 | ) | 3 | (5 | ) | (5 | ) | 2 | 1 | (59 | ) | 1 | 5 | (50 | ) | ||||||||||||||||||||||||||||||
Amounts reclassified from AOCI(b) | (3 | ) | — | 104 | 5 | — | 106 | 4 | — | 36 | — | — | 40 | |||||||||||||||||||||||||||||||||||
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Net current-period OCI | (4 | ) | — | 102 | 8 | (5 | ) | 101 | 6 | 1 | (23 | ) | 1 | 5 | (10 | ) | ||||||||||||||||||||||||||||||||
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Ending balance | $ | (23 | ) | $ | 3 | $ | (2,463 | ) | $ | (32 | ) | $ | (8 | ) | $ | (2,523 | ) | $ | (11 | ) | $ | 5 | $ | (2,633 | ) | $ | (29 | ) | $ | (2 | ) | $ | (2,670 | ) | ||||||||||||||
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Generation(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Beginning balance | $ | (21 | ) | $ | 1 | $ | — | $ | (40 | ) | $ | (3 | ) | $ | (63 | ) | $ | (19 | ) | $ | 2 | $ | — | $ | (30 | ) | $ | (7 | ) | $ | (54 | ) | ||||||||||||||||
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OCI before reclassifications | — | 1 | — | 3 | 1 | 5 | 2 | — | — | 1 | 6 | 9 | ||||||||||||||||||||||||||||||||||||
Amounts reclassified from AOCI(b) | (3 | ) | — | — | 5 | — | 2 | 4 | — | — | — | — | 4 | |||||||||||||||||||||||||||||||||||
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Net current-period OCI | (3 | ) | 1 | — | 8 | 1 | 7 | 6 | — | — | 1 | 6 | 13 | |||||||||||||||||||||||||||||||||||
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Ending balance | $ | (24 | ) | $ | 2 | $ | — | $ | (32 | ) | $ | (2 | ) | $ | (56 | ) | $ | (13 | ) | $ | 2 | $ | — | $ | (29 | ) | $ | (1 | ) | $ | (41 | ) | ||||||||||||||||
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PECO(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Beginning balance | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||||||||||||||||
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OCI before reclassifications | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Amounts reclassified from AOCI(b) | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
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Net current-period OCI | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
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Ending balance | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||||||||||||||||
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PHI Predecessor(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Beginning balance January 1, 2016 | $ | (8 | ) | $ | — | $ | (28 | ) | $ | — | $ | — | $ | (36 | ) | |||||||||||||||||||||||||||||||||
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OCI before reclassifications | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
Amounts reclassified from AOCI(b) | — | — | 1 | — | — | 1 | ||||||||||||||||||||||||||||||||||||||||||
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Net current-period OCI | — | — | 1 | — | — | 1 | ||||||||||||||||||||||||||||||||||||||||||
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Ending balance March 23, 2016(c) | $ | (8 | ) | $ | — | $ | (27 | ) | $ | — | $ | — | $ | (35 | ) | |||||||||||||||||||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Nine Months Ended September 30, 2015 | Gains and (losses) on Hedging Activity | Unrealized Gains and (losses) on Marketable Securities | Pension and Non-Pension Postretirement Benefit Plan Items | Foreign Currency Items | AOCI of Equity Investments | Total | ||||||||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, 2016 | Gains and (losses) on Hedging Activity | Unrealized Gains and (losses) on Marketable Securities | Pension and Non-Pension Postretirement Benefit Plan Items | Foreign Currency Items | AOCI of Equity Investments | Total | ||||||||||||||||||||||||||||||||||||||||||
Exelon(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Beginning balance | $ | (28 | ) | $ | 3 | $ | (2,640 | ) | $ | (19 | ) | $ | — | $ | (2,684 | ) | $ | (19 | ) | $ | 3 | $ | (2,565 | ) | $ | (40 | ) | $ | (3 | ) | $ | (2,624 | ) | |||||||||||||||
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OCI before reclassifications | (18 | ) | — | (29 | ) | (17 | ) | — | (64 | ) | (10 | ) | (1 | ) | (1 | ) | 6 | (3 | ) | (9 | ) | |||||||||||||||||||||||||||
Amounts reclassified from AOCI(b) | 22 | — | 130 | — | — | 152 | 3 | — | 34 | — | — | 37 | ||||||||||||||||||||||||||||||||||||
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Net current-period OCI | 4 | — | 101 | (17 | ) | — | 88 | (7 | ) | (1 | ) | 33 | 6 | (3 | ) | 28 | ||||||||||||||||||||||||||||||||
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Ending balance | $ | (24 | ) | $ | 3 | $ | (2,539 | ) | $ | (36 | ) | $ | — | $ | (2,596 | ) | $ | (26 | ) | $ | 2 | $ | (2,532 | ) | $ | (34 | ) | $ | (6 | ) | $ | (2,596 | ) | |||||||||||||||
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Generation(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Beginning balance | $ | (18 | ) | $ | 1 | $ | — | $ | (19 | ) | $ | — | $ | (36 | ) | $ | (21 | ) | $ | 1 | $ | — | $ | (40 | ) | $ | (3 | ) | $ | (63 | ) | |||||||||||||||||
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OCI before reclassifications | (13 | ) | — | — | (17 | ) | — | (30 | ) | (8 | ) | — | — | 6 | (2 | ) | (4 | ) | ||||||||||||||||||||||||||||||
Amounts reclassified from AOCI(b) | 6 | — | — | — | — | 6 | 3 | — | — | — | — | 3 | ||||||||||||||||||||||||||||||||||||
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Net current-period OCI | (7 | ) | — | — | (17 | ) | — | (24 | ) | (5 | ) | — | — | 6 | (2 | ) | (1 | ) | ||||||||||||||||||||||||||||||
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Ending balance | $ | (25 | ) | $ | 1 | $ | — | $ | (36 | ) | $ | — | $ | (60 | ) | $ | (26 | ) | $ | 1 | $ | — | $ | (34 | ) | $ | (5 | ) | $ | (64 | ) | |||||||||||||||||
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PECO(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Beginning balance | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||||||||||||||||
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OCI before reclassifications | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Amounts reclassified from AOCI(b) | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
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Net current-period OCI | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
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Ending balance | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||||||||||||||||
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PHI Predecessor(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Beginning balance | $ | (9 | ) | $ | — | $ | (37 | ) | $ | — | $ | — | $ | (46 | ) | |||||||||||||||||||||||||||||||||
Beginning balance January 1, 2016 | $ | (8 | ) | $ | — | $ | (28 | ) | $ | — | $ | — | $ | (36 | ) | |||||||||||||||||||||||||||||||||
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OCI before reclassifications | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Amounts reclassified from AOCI(b) | 1 | — | 4 | — | — | 5 | — | — | 1 | — | — | 1 | ||||||||||||||||||||||||||||||||||||
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Net current-period OCI | 1 | — | 4 | — | — | 5 | — | — | 1 | — | — | 1 | ||||||||||||||||||||||||||||||||||||
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Ending balance | $ | (8 | ) | $ | — | $ | (33 | ) | $ | — | $ | — | $ | (41 | ) | |||||||||||||||||||||||||||||||||
Ending balance March 23, 2016(c) | $ | (8 | ) | $ | — | $ | (27 | ) | $ | — | $ | — | $ | (35 | ) | |||||||||||||||||||||||||||||||||
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(a) | All amounts are net of tax and noncontrolling interest. Amounts in parenthesis represent a decrease in AOCI. |
(b) | See next tables for details about these reclassifications. |
(c) | As a result of the PHI Merger, the PHI predecessor balances at March 23, 2016 were reduced to zero on March 24, 2016 due to purchase accounting adjustments applied to PHI. |
ComEd, PECO, BGE, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the three and nine months ended September 30, 2016March 31, 2017 and 2015.2016. The following tables present amounts reclassified out of AOCI to Net income for Exelon, Generation and PHI during the three and nine months ended September 30, 2016March 31, 2017 and 2015.2016.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Three Months Ended September 30, 2016March 31, 2017
Details about AOCI components | Items reclassified out of AOCI(a) | Affected line item in the Statement of Operations and Comprehensive Income | ||||||||
Exelon | Generation | |||||||||
Amortization of pension and other postretirement benefit plan items | ||||||||||
Prior service costs(b) | $ | 19 | $ | — | ||||||
Actuarial losses(b) | (76 | ) | — | |||||||
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| |||||||
Total before tax | (57 | ) | — | |||||||
Tax benefit | 22 | — | ||||||||
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| |||||||
Net of tax | $ | (35 | ) | $ | — | |||||
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| |||||||
Gains (losses) on foreign currency translation | ||||||||||
Other | $ | (5 | ) | $ | (5 | ) | Other income and (deductions) | |||
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| |||||||
Total before tax | (5 | ) | (5 | ) | ||||||
Tax expense | — | — | ||||||||
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| |||||||
Net of tax | $ | (5 | ) | $ | (5 | ) | ||||
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| |||||||
Total Reclassifications for the period | $ | (40 | ) | $ | (5 | ) | Comprehensive income | |||
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Nine Months Ended September 30, 2016
Details about AOCI components | Items reclassified out of AOCI(a) | Affected line item in the Statement of | ||||||||||||
Predecessor | ||||||||||||||
January 1, 2016 to March 23, 2016 | ||||||||||||||
Exelon | Generation | PHI | ||||||||||||
Gains and (losses) on cash flow hedges | ||||||||||||||
Other cash flow hedges | $ | 5 | $ | 5 | $ | — | Interest expense | |||||||
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| |||||||||
Total before tax | 5 | 5 | — | |||||||||||
Tax expense | (2 | ) | (2 | ) | — | |||||||||
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| |||||||||
Net of tax | $ | 3 | $ | 3 | $ | — | Comprehensive income | |||||||
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| |||||||||
Amortization of pension and other postretirement benefit plan items | ||||||||||||||
Prior service costs(b) | $ | 57 | $ | — | $ | — | ||||||||
Actuarial losses(b) | (227 | ) | — | (1 | ) | |||||||||
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| |||||||||
Total before tax | (170 | ) | — | (1 | ) | |||||||||
Tax benefit | 66 | — | — | |||||||||||
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| |||||||||
Net of tax | $ | (104 | ) | $ | — | $ | (1 | ) | ||||||
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| |||||||||
Gains (losses) on foreign currency translation | ||||||||||||||
Other | $ | (5 | ) | $ | (5 | ) | $ | — | Other income and (deductions) | |||||
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| |||||||||
Total before tax | (5 | ) | (5 | ) | — | |||||||||
Tax expense | — | — | — | |||||||||||
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| |||||||||
Net of tax | $ | (5 | ) | $ | (5 | ) | $ | — | ||||||
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| |||||||||
Total Reclassifications | $ | (106 | ) | $ | (2 | ) | $ | (1 | ) | Comprehensive income | ||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Details about AOCI components | Items reclassified out of AOCI(a) | Affected line item in the Statement | ||||||||
Exelon | Generation | |||||||||
Gains and (losses) on cash flow hedges | ||||||||||
Other cash flow hedges | $ | (7 | ) | $ | (7 | ) | Interest expense | |||
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| |||||||
Total before tax | (7 | ) | (7 | ) | ||||||
Tax benefit | 3 | 3 | ||||||||
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| |||||||
Net of tax | $ | (4 | ) | $ | (4 | ) | Comprehensive income | |||
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| |||||||
Amortization of pension and other postretirement benefit plan items | ||||||||||
Prior service costs(b) | $ | 23 | $ | — | ||||||
Actuarial losses(b) | (81 | ) | — | |||||||
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| |||||||
Total before tax | (58 | ) | — | |||||||
Tax benefit | 22 | — | ||||||||
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| |||||||
Net of tax | $ | (36 | ) | $ | — | |||||
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| |||||||
Total Reclassifications | $ | (40 | ) | $ | (4 | ) | Comprehensive income | |||
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Three Months Ended September 30, 2015March 31, 2016
Details about AOCI components | Items reclassified out of AOCI(a) | Affected line item in the Statement of Income | ||||||||||||
Predecessor | ||||||||||||||
Exelon | Generation | PHI | ||||||||||||
Gains and (losses) on cash flow hedges | ||||||||||||||
Other cash flow hedges | $ | (4 | ) | $ | (4 | ) | $ | (1 | ) | Interest expense | ||||
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| |||||||||
Total before tax | (4 | ) | (4 | ) | (1 | ) | ||||||||
Tax expense | 1 | 1 | — | |||||||||||
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| |||||||||
Net of tax | $ | (3 | ) | $ | (3 | ) | $ | (1 | ) | Comprehensive income | ||||
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| |||||||||
Amortization of pension and other postretirement benefit plan items | ||||||||||||||
Prior service costs(b) | $ | 19 | $ | — | $ | — | ||||||||
Actuarial losses(b) | (90 | ) | — | (2 | ) | |||||||||
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| |||||||||
Total before tax | (71 | ) | — | (2 | ) | |||||||||
Tax expense | 28 | — | 2 | |||||||||||
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| |||||||||
Net of tax | $ | (43 | ) | $ | — | $ | — | |||||||
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| |||||||||
Total Reclassifications for the period | $ | (46 | ) | $ | (3 | ) | $ | (1 | ) | Comprehensive income | ||||
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Nine Months Ended September 30, 2015
Details about AOCI components | Items reclassified out of AOCI(a) | Affected line item in the Statement of Income | Items reclassified out of AOCI(a) | Affected line item in the Statement | ||||||||||||||||||||||||
Predecessor | Predecessor | |||||||||||||||||||||||||||
Exelon | Generation | PHI | Exelon | Generation | PHI | |||||||||||||||||||||||
Gains and (losses) on cash flow hedges | ||||||||||||||||||||||||||||
Terminated interest rate swaps | $ | (26 | ) | $ | — | $ | — | Other, net | ||||||||||||||||||||
Energy related hedges | 2 | 2 | — | Operating revenues | ||||||||||||||||||||||||
Other cash flow hedges | (11 | ) | (11 | ) | (1 | ) | Interest expense | $ | (5 | ) | $ | (5 | ) | — | Interest expense | |||||||||||||
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| |||||||||||||||||||||||
Total before tax | (35 | ) | (9 | ) | (1 | ) | (5 | ) | (5 | ) | — | |||||||||||||||||
Tax benefit | 13 | 3 | — | |||||||||||||||||||||||||
Tax expense | 2 | 2 | — | |||||||||||||||||||||||||
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| |||||||||||||||||||||||
Net of tax | $ | (22 | ) | $ | (6 | ) | $ | (1 | ) | Comprehensive income | $ | (3 | ) | $ | (3 | ) | $ | — | Comprehensive income | |||||||||
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| |||||||||||||||||||||||
Amortization of pension and other postretirement benefit plan items | ||||||||||||||||||||||||||||
Prior service costs(b) | $ | 57 | $ | — | $ | — | $ | 20 | $ | — | $ | — | ||||||||||||||||
Actuarial losses(b) | (270 | ) | — | (7 | ) | (76 | ) | — | (1 | ) | ||||||||||||||||||
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| |||||||||||||||||||||||
Total before tax | (213 | ) | — | (7 | ) | (56 | ) | — | (1 | ) | ||||||||||||||||||
Tax benefit | 83 | — | 3 | 22 | — | — | ||||||||||||||||||||||
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| |||||||||||||||||||||||
Net of tax | $ | (130 | ) | $ | — | $ | (4 | ) | $ | (34 | ) | $ | — | $ | (1 | ) | ||||||||||||
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Total Reclassifications | $ | (152 | ) | $ | (6 | ) | $ | (5 | ) | Comprehensive income | $ | (37 | ) | $ | (3 | ) | $ | (1 | ) | Comprehensive income | ||||||||
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(a) | Amounts in parenthesis represent a decrease in net income. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(b) | This AOCI component is included in the computation of net periodic pension and OPEB cost (see Note 13 — Retirement Benefits for additional details). |
The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the three and nine months ended September 30, 2016 and 2015:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Exelon | ||||||||||||||||
Pension and non-pension postretirement benefit plans: | ||||||||||||||||
Prior service benefit reclassified to periodic benefit cost | $ | 7 | $ | 8 | $ | 22 | $ | 22 | ||||||||
Actuarial loss reclassified to periodic cost | (29 | ) | (35 | ) | (88 | ) | (105 | ) | ||||||||
Pension and non-pension postretirement benefit plans valuation adjustment | 1 | — | 1 | 17 | ||||||||||||
Change in unrealized gain/(loss) on cash flow hedges | (1 | ) | 3 | 3 | (3 | ) | ||||||||||
Change in unrealized loss on equity investments | — | — | 3 | — | ||||||||||||
Change in unrealized gain on marketable securities | (1 | ) | — | (1 | ) | — | ||||||||||
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| |||||||||
Total | $ | (23 | ) | $ | (24 | ) | $ | (60 | ) | $ | (69 | ) | ||||
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| |||||||||
Generation | ||||||||||||||||
Change in unrealized gain/(loss) on cash flow hedges | $ | (2 | ) | $ | 3 | $ | 1 | $ | 4 | |||||||
Change in unrealized loss on equity investments | — | — | 3 | — | ||||||||||||
Change in unrealized gain on marketable securities | — | — | — | — | ||||||||||||
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Total | $ | (2 | ) | $ | 3 | $ | 4 | $ | 4 | |||||||
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Predecessor | ||||||||||||
PHI | Three Months Ended September 30, 2015 | January 1, 2016 to March 23, 2016 | Nine Months Ended September 30, 2015 | |||||||||
Pension and non-pension postretirement benefit plans: | ||||||||||||
Actuarial loss reclassified to periodic cost | $ | (2 | ) | $ | — | $ | (3 | ) |
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Contingently Redeemable Noncontrolling Interests (Exelon and Generation)
In November 2015, 2015 ESA Investco, LLC, a wholly owned subsidiary of Generation, entered into an arrangement to sell a portion of its equity to a tax equity investor. Pursuant to the operating agreement, in certain circumstances the equity contributed by the noncontrolling interests holder could be contingently redeemable. These circumstances are outside of the control of Generation and the noncontrolling interests holder resulting in a portion of the noncontrolling interests being considered contingently redeemable and thus presented in mezzanine equity on the consolidated balance sheet.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following table summarizespresents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the changes in the contingently redeemable noncontrolling interests for the ninethree months ended September 30,March 31, 2017 and 2016:
Balance at December 31, 2015 | $ | 28 | ||
Cash received from noncontrolling interests | 105 | |||
Release of contingency | (107 | ) | ||
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| |||
Balance at September 30, 2016 | $ | 26 | ||
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Preferred Stock (PHI)
In connection with the PHI Merger Agreement, Exelon purchased 18,000 originally issued shares of PHI preferred stock for a purchase price of $180 million. PHI excluded the preferred stock from equity at December 31, 2015 since the preferred stock contained conditions for redemption that were not solely within the control of PHI. Management determined that the preferred stock contained embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding preferred stock could be called and redeemed at a nominal par value upon a termination of the merger agreement under certain circumstances due to the failure to obtain required regulatory approvals. The embedded call and redemption features on the shares of the preferred stock in the event of such a termination were separately accounted for as derivatives. As of December 31, 2015, the fair value of the derivative related to the preferred stock was estimated to be $18 million based on PHI’s updated assessment and was included in Current assets with a corresponding increase in Preferred stock on PHI’s Consolidated Balance Sheets. Immediately prior to the merger date, PHI updated its assessment of the fair value of the derivative and reduced the fair value to zero, recording the $18 million decrease in fair value as a reduction of Other, within PHI’s predecessor period, January 1, 2016 to March 23, 2016, Consolidated Statements of Operations and Comprehensive Income.
On March 23, 2016, the preferred stock was cancelled and the $180 million cash consideration previously received by PHI to issue the preferred stock was treated as additional merger purchase price consideration.
Three Months Ended March 31, | ||||||||
2017 | 2016 | |||||||
Exelon | ||||||||
Pension andnon-pension postretirement benefit plans: | ||||||||
Prior service benefit reclassified to periodic benefit cost | $ | 10 | $ | 7 | ||||
Actuarial loss reclassified to periodic benefit cost | (32 | ) | (30 | ) | ||||
Pension andnon-pension postretirement benefit plans valuation adjustment | — | — | ||||||
Change in unrealized (loss)/gain on cash flow hedges | (1 | ) | 3 | |||||
Change in unrealized (loss)/gain on equity investments | (4 | ) | 2 | |||||
Change in unrealized (loss)/gain on marketable securities | (1 | ) | 1 | |||||
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| |||||
Total | $ | (28 | ) | $ | (17 | ) | ||
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| |||||
Generation | ||||||||
Change in unrealized (loss)/gain on cash flow hedges | $ | (1 | ) | $ | 2 | |||
Change in unrealized (loss)/gain on equity investments | (3 | ) | 2 | |||||
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| |||||
Total | $ | (4 | ) | $ | 4 | |||
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Predecessor | ||||
PHI | 2016 to March 23, 2016 | |||
| ||||
Actuarial loss reclassified to periodic cost | $ | — |
16. Earnings Per Share and Equity (Exelon)
Earnings per Share (Exelon)
Diluted earnings per share is calculated by dividing Net income attributable to common shareholders by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options, performance share awards and restricted stock outstanding under Exelon’s LTIPs considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||
Exelon | ||||||||||||||||||||||||
Net income attributable to common shareholders | $ | 490 | $ | 629 | $ | 930 | $ | 1,959 | $ | 995 | $ | 173 | ||||||||||||
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Weighted average common shares outstanding — basic | 925 | 913 | 924 | 879 | 928 | 923 | ||||||||||||||||||
Assumed exercise and/or distributions of stock-based awards | 2 | 2 | 2 | 4 | 2 | 2 | ||||||||||||||||||
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Weighted average common shares outstanding — diluted | 927 | 915 | 926 | 883 | 930 | 925 | ||||||||||||||||||
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The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 9 million and 13 million for the three months ended March 31, 2017
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The number of stock optionsand 2016, respectively. There were no equity units related to the PHI Merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 11 million and 12 million for the three and nine months ended September 30, 2016, respectively and 14 million for three and nine months ended September 30, 2015.March 31, 2017. The number of equity units related to the PHI Merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect was less than 14 million for the three and nine months ended September 30, 2016, respectively, and 4 million and 2 million for the three and nine months ended September 30, 2015, respectively.March 31, 2016. Refer to Note 1920 — Shareholder’sShareholders’ Equity of the Exelon 20152016 Form10-K for further information regarding the equity units.
Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of September 30, 2016.March 31, 2017. In 2008, Exelon management decided to defer indefinitely any share repurchases.
17. Commitments and Contingencies (Preference Stock Redemption (BGE)All Registrants)
BGE had $190 million of cumulative preference stock that was redeemable at its option at any time after October 1, 2015 for the redemption price of $100 per share, plus accrued and unpaid dividends. On July 3, 2016, BGE redeemed all 400,000 shares of its outstanding 7.125% Cumulative Preference Stock, 1993 Series and all 600,000 shares of its outstanding 6.99% Cumulative Preference Stock, 1995 Series for $100 million, plus accrued and unpaid dividends. On September 18, 2016, BGE redeemed the remaining 500,000 shares of its outstanding 6.970% Cumulative Preference Stock, 1993 Series and the remaining 400,000 shares of its outstanding 6.70% Cumulative Preference Stock, 1993 Series for $90 million, plus accrued and unpaid dividends.
|
The following is an update to the current status of commitments and contingencies set forth in Note 2324 of the Exelon 20152016 Form10-K and Note 16 of the PHI 2015 Form 10-K. . See Note 4 — Mergers, Acquisitions and Dispositions for further discussion on the PHI Merger commitments.
Commitments
Constellation Merger Commitments (Exelon and Generation)
In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion. The direct investment estimate includes $95 million to $120 million relating to the construction of a headquarters building in Baltimore for Generation’s competitive energy businesses.
The direct investment commitment also includes $450 million to $550 million relating to Exelon and Generation’s development or assistance in the development of 275285 — 300 MWs of new generation in Maryland, which is expected to be completed overwithin a period of 10 years. As of September 30, 2016, Exelon and Generation have incurred $404 million towards satisfying the commitment for new generation development in the state of Maryland, with approximately 220 MW of the new generation commencing with commercial operations to date. The MDPSC Orderorder contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damages payments. Exelon and Generation expect thathave incurred $456 million towards satisfying the majoritycommitment for new generation development in the state of these commitmentsMaryland, with approximately 220 MW of the new generation commencing with commercial operations to date. During the fourth quarter of 2016, given continued declines in projected energy and capacity prices, Generation terminated rights to certain development projects originally intended to meet its remaining 55 MW commitment amount. The commitment will now most likely be satisfied via payment of liquidated damages or execution of a third party PPA, rather than by building or acquiringGeneration constructing renewable generating assetsassets. As a result, Exelon and therefore, will be primarily capitalGeneration recorded apre-tax $50 million loss contingency in natureOperating and recognized as incurred. However, duringmaintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the third quarter of 2014, the conditions associated with one of theyear ended December 31, 2016.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
generation development commitments changed such that Exelon and Generation believe that the most likely outcome will involve making subsidy payments and/or liquidated damages payments rather than constructing the specified generating plant. As a result, Exelon and Generation recorded a pre-tax $44 million loss contingency related to this generation development commitment. While this $44 million loss contingency represents Generation’s best estimate of the future obligation, it is reasonably possible that Exelon and Generation could ultimately be required to make cumulative subsidy payments of up to a maximum of approximately $105 million over a 20-year period dependent on actual generating output from a successfully constructed generating plant.
Equity Investment Commitments (Exelon and Generation)
As part of Generation’s recent investments in technology development, Generation has enteredenters into equity purchase agreements that include commitments to invest additional equity through incremental payments to fund the anticipated needs of the planned operations of the associated companies. The commitments include approximately $20 million of in-kind services and 100% of 2015 ESA Investco, LLC’s equity commitment since 2015 ESA Investco, LLC is consolidated by Generation (see Note 3 —Variable Interest Entities for additional details). As of September 30, 2016,March 31, 2017, Generation’s estimated commitments relating to its equity purchase agreements, including thein-kind services contributions, is anticipated to be as follows:
Total | ||||
2016(a) | $ | 79 | ||
2017 | 25 | |||
2018 | 4 | |||
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| |||
Total | $ | 108 | ||
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Total | ||||
2017 | $ | 9 | ||
2018 | 7 | |||
2019 | 3 | |||
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| |||
Total | $ | 19 | ||
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Commercial Commitments (All Registrants)
The Registrants’ commercial commitments as of September 30, 2016,March 31, 2017 , representing commitments potentially triggered by future events were as follows:
Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Letters of credit (non-debt)(a) | $ | 1,720 | $ | 1,650 | $ | 16 | $ | 23 | $ | 2 | $ | 1 | $ | — | $ | — | $ | 1 | $ | 1,527 | $ | 1,440 | $ | 14 | $ | 23 | $ | 5 | $ | 1 | $ | 1 | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||
Surety bonds(b) | 1,084 | 984 | 10 | 9 | 11 | 16 | 9 | 4 | 3 | 1,038 | 964 | 5 | 7 | 11 | 16 | 9 | 4 | 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Financing trust guarantees | 628 | — | 200 | 178 | 250 | — | — | — | — | 628 | — | 200 | 178 | 250 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear insurance premiums(c) | 3,045 | 3,045 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Guaranteed lease residual values(d) | 20 | — | — | — | — | 20 | 6 | 7 | 5 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Guaranteed lease residual values(c) | 19 | — | — | — | — | 19 | 5 | 7 | 5 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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(a) | Letters of credit(non-debt) — Exelon and certain subsidiaries maintainnon-debt letters of credit to provide credit support for certain transactions as requested by third parties. |
(b) | Surety bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
(c) |
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be |
Nuclear Insurance (Exelon and Generation)
Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.
The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of September 30, 2016,March 31, 2017 , the current liability limit per incident is $13.4
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
$13.4 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. An inflation adjustment must be madereactors at least once every 5five years andwith the last inflation adjustment was made effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. As of September 30, 2016,Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $375$450 million for each operating site. Additionally, the Price-Anderson Act requires a second layer of protectionClaims exceeding that amount are covered through the mandatory participation in a retrospective rating plan for power reactors (currently 102 reactors) resulting in anfinancial protection pool, as required by the PriceAnderson-Act, which provides the additional $13.0 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Under the Price-Anderson Act, the maximum assessment in the eventExelon’s share of an incident for each nuclear operator, per reactor, per incident (including a 5% surcharge), is $127.3 million, payable at no more than $19 million per reactor per incident per year. Exelon’s maximum liability per incident isthis secondary layer would be approximately $2.7$2.8 billion, including CENG’s related liability.liability, however any amounts payable under this secondary layer would be capped at $420 million per year.
In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.4 billion limit for a single incident.
As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 5 —Investment in Constellation Energy Nuclear Group, LLC of the Exelon 20152016 Form10-K for additional information on Generation’s operations relating to CENG.
Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.
Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $373 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.
NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery for all losses by all insuredsExelon will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.
For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and liquidity.
Environmental Issues(All Registrants)
General. The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, 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.
ComEd, PECO, BGE and DPL have identified sites where former MGP 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 42 sites, 1718 of which the remediation has been completed and approved by the Illinois EPA or the U.S. EPA and 2524 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2021.
PECO has identified 26 sites, 1617 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 109 sites 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.
BGE has identified 13 former gas manufacturing or purification sites that it currently owns or owned at one time through a predecessor’s acquisition. Two gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. The required costs at these two sites are not considered material. One formerThe first phase of an investigation of an additional gas purification site is currently under investigation(Riverside) was completed during the first quarter of 2015 at the direction of the MDE.MDE and investigations continue under MDE’s direction. For more information, see the discussion of the Riverside site below.
DPL has identified 2 sites, all of which the remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control.
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. ComEd and PECO have recorded regulatory assets for the recovery of these costs. See Note 5 —Regulatory Matters for additional information regarding the associated regulatory assets. BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of the former MGP facility sites from customers; however, while BGE does not have a rider for MGPclean-up costs, BGE has historically received recovery of actualclean-up costs in distribution rates. DPL has historically received recovery of actualclean-up costs in distribution rates.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. DPL has historically received recovery of actual clean-up costs in distribution rates.
As of September 30, 2016Three Months Ended March 31, 2017 and December 31, 2015,2016, 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, 2016 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation(a) | ||||||||||||||
March 31, 2017 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||||||||||
Exelon | $ | 427 | $ | 318 | $ | 425 | $ | 319 | ||||||||
Generation | 76 | — | 71 | — | ||||||||||||
ComEd | 283 | 281 | 288 | 286 | ||||||||||||
PECO | 36 | 34 | 33 | 31 | ||||||||||||
BGE | 2 | 2 | 4 | 2 | ||||||||||||
PHI (Successor) | 30 | 1 | 29 | — | ||||||||||||
Pepco | 27 | — | 26 | — | ||||||||||||
DPL | 2 | 1 | 2 | — | ||||||||||||
ACE | 1 | — | 1 | — |
December 31, 2015 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation(a) | ||||||
Exelon | $ | 369 | $ | 301 | ||||
Generation | 63 | — | ||||||
ComEd | 266 | 264 | ||||||
PECO | 37 | 35 | ||||||
BGE | 3 | 2 | ||||||
PHI (Predecessor) | 33 | 1 | ||||||
Pepco | 24 | — | ||||||
DPL | 3 | 1 | ||||||
ACE | 1 | — |
|
December 31, 2016 | Total Environmental Investigation and Remediation Reserve | Portion of Total Related to MGP Investigation and Remediation | ||||||
Exelon | $ | 429 | $ | 325 | ||||
Generation | 72 | — | ||||||
ComEd | 292 | 291 | ||||||
PECO | 33 | 31 | ||||||
BGE | 2 | 2 | ||||||
PHI (Successor) | 30 | 1 | ||||||
Pepco | 27 | — | ||||||
DPL | 2 | 1 | ||||||
ACE | 1 | — |
The historical nature of the MGP 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.
During the third quarter of 2016, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The results of the study resulted in a $7 million and $2 million increase to environmental liabilities and related regulatory assets for ComEd and PECO, respectively.
The Registrants cannot reasonably estimate whether they will incur other 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Water Quality
Groundwater Contamination. In October 2007, a subsidiary of Constellation entered into a consent decree with the MDE relating to groundwater contamination at a third-party facility that was licensed to accept fly ash, a byproduct generated by coal-fired plants. The consent decree required the payment of a $1 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. Generation’s remaining groundwater contamination reserve was approximately $13 million at September 30, 2016 and $12 million at December 31, 2015.
Benning Road Site NPDES Permit Limit Exceedances.Pepco holds an NPDES permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road site, including the Pepco Energy Services generating facility previously located on the site that was deactivated in 2012 and subsequently demolished.service facility. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River as determined by EPA to be necessary to meet the applicable District of Columbia surface water quality standards.River. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). As of December 2012, Pepco completed the implementation of the first two phases ofThe BMPs identified in a plan approved by EPA (consisting principally of installing metal absorbing filters to capture contaminants at storm water inlets, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for metals. Most of the quarterly monitoring results since the issuance of the permit have shown exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead.
The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road site has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. In December 2014, Pepco submitted a plan to EPA to implement the third phase of BMPs recommended in the original permit compliance plan with the objective of achieving full compliance with the permit limits for metals by the end of 2015 and Pepco immediately began to implement the additional BMPs in accordance with the plan. On September 1, 2015, Pepco submitted a report to EPA on the status of implementation of the third phase of BMPs. As of that date, Pepco had fully implemented most of the elements of the Phase 3 plan, including installation of upgraded storm water inlet controls (filters and booms), enhanced inspection and maintenance of inlets, removal of materials and equipment from exposure to storm water, and removal of accumulated sediments from the underground storm drains. The sampling results from the third quarter of 2015 showed compliance with all of the permit limits. However, more recent sampling results continued to show modest exceedances for copper and zinc. As confirmed by this latest sampling, because the permit limits are low and site conditions are subject to variation, Pepco has concluded that some form of storm water treatment prior to discharge will be necessary to ensure ongoing compliance with all permit limits and has begun the process of evaluating treatment options. The nature and scope of the necessary treatment system, and the amount of the associated capital expenditures, will not be known until Pepco has completed the evaluation and design process.
Pepco has been engaged in discussions with representatives from EPA and the DOJ regarding permit compliance. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court. Pepco expects that this enforcement action will be resolved through a consent decree that will (i) establish further requirements to achieve compliance with the permit limits, including the design and installation of an appropriate storm water treatment system as noted above, and (ii) include civil penalties for past noncompliance. Pepco has established what it believes is an appropriate reserve for potential penalties which ismetals.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
includedThe 2009 permit remains in effect pending EPA’s action on the table above. Pepco does not expect the amount of such penalties above the financial reserve to have a material adverse effect on Exelon’s, PHI’s and Pepco’s consolidated financial condition, results of operations or cash flows.
Pepco and EPA are currently in discussions regarding the termsrenewal application, including resolution of the contemplated consent decree,stormwater compliance issues. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court, and it is anticipated that the parties will finalize the consent decree before the end of 2016. In response to a joint motion by the parties, the court has extended the deadline for Pepco to answer the complaint to November 15, 2016, to give the parties time to work towards agreement on the terms of a consent decree. The parties contemplate seeking a further extension if necessary to complete their negotiations. Once executed by the parties, the consent decree will be filed with the court for review and approval following a period for public comment.
Onin March 14, 2016 the court granted a motion by the Anacostia Riverkeeper to intervene in this case as a plaintiff along with EPA. As an intervenor,Since 2009 Pepco has installed runoff mitigation measures and implemented new operating procedures to comply with regulations. In January 2017, the Anacostia Riverkeeperparties agreed to a settlement in the form of a Consent Decree whereby Pepco will be entitledpay a civil penalty in the amount of $1.6 million, continue the BMPs to filemanage stormwater, construct a brief commenting onnew stormwater treatment system, and make certain other capital improvements to the proposed consent decreestormwater management system. The Consent Decree has been lodged with the Court and has been subject to appeal any decision bya30-day public comment period. Upon completion of its review of public comments, It is expected that the court toCourt will approve the consent decree overConsent Decree in the Anacostia Riverkeeper’s objection, but its participationsecond quarter of 2017. Pepco has established appropriate accruals for the liabilities under the Consent Agreement, which is not expected to materially affectincluded in the progress or outcome of the consent decree negotiations.table above.
Solid and Hazardous Waste
Cotter Corporation. 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. On February 18,In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. The current estimated cost of the landfill cover remediation for the site is approximately $90 million, including escalation, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability.liability, which is included in the table above. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the supplemental feasibility study to the EPA for review. Since June 2012, the EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study, that are now scheduled to bewere completed in the fall of 2016 to enable the EPA to propose a remedy for public comment by the end ofDecember 2016. While the EPA has not yet formally announced a change inschedule for selection of the schedule,final remedy, the PRPs believe that the final supplemental feasibility study will not be completed until year-end 2016 and the EPA announcement of the proposed remedy will not take place inuntil the thirdend of 2017, or possibly the first quarter of 2017.2018. Thereafter, the EPA will select a final remedy and seek to enter into a Consent Decree with the PRPs to effectuate the remedy. Recent investigation has identified a number of other parties who may be PRPs and could be liable to contribute to the final remedy. Further investigation is underway. Generation believes that a partial excavation remedy is reasonably possible, but does not currently haveand the partial excavation costs, inclusive of a basislandfill cover, could range from approximately $225 million to establish a reasonable estimate$650 million; such costs would likely be shared by the final group of the range of costs.identified PRPs. Generation believes the likelihood that the EPA would require a complete excavation remedy is remote. The cost of a partial or complete excavation could have a material, unfavorable impact on Generation’s and Exelon’s future results of operations and cash flows.
During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent and dangerous conditions at the landfill. The first involved installation by the PRPs of anon-combustible surface cover to protect against surface fires in areas where radiological materials are believed to have been disposed. Generation has accrued what it believes to be an adequate amount to cover its anticipated liability for this interim action. The second action involved EPA’s public statement that it will require the PRPs to construct a barrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
West Lake Landfill where radiological materials are believed to have been disposed. At this time, EPA has not provided sufficient details related to the basis for and the requirements and design of a barrier wall to enable Generation to determine the likelihood such a remedy will ultimately be implemented, assess the degree to which
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation may have liability as a potentially responsible party, or develop a reasonable estimate of the potential incremental costs. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Generation’s and Exelon’s future results of operations and cash flows. Finally, one of the other PRP’s,PRPs, the landfill owner and operator of the adjacent landfill, has indicated that it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Generation and Exelon do not possess sufficient information to assess this claim and are therefore unable to determine the impact on their future results of operations and cash flows.
On February 2, 2016, the U.S. Senate passed a bill to transfer remediation authority over the West Lake Landfill from the EPA to the U.S. Army Corps of Engineers, under the Formerly Utilized Sites Remedial Action Program (FUSRAP). SuchThe legislation would become final upon passagewas not passed in the U.S. House of Representatives, and would therefore require reintroduction in the signatureSenate for consideration in the current session of the President, andCongress. Should such proposed legislation ultimately become law, it would be subject to annual funding appropriations in the U.S. Budget. Remediation under FUSRAP would not alter the liability of the PRPs, but couldwould likely delay the determination of a final remedy and its implementation.
On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’sclean-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 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 the 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. The DOJ and the PRPs agreed to toll the statute of limitations until August 2017 so that settlement discussions could proceed. Based on Generation’s preliminary review, it appears probable that Generation has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability.liability, which is included in the table above.
Commencing in February 2012, 63a number of lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, andas well as Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer or other serious illness due to Cotter’s negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have assertedare asserting public liability claims under the Price-Anderson Act. Their state law claims for negligence, strict liability, emotional distress, and medical monitoring and violations of the Price-Anderson Act.have been dismissed. The complaints do not contain specific damage claims. In the event of a finding of liability against Cotter, it is reasonably possible that Exelon would be considered liablefinancially responsible due to its indemnification responsibilities of Cotter described above. The court has dismissed thea number of lawsuits, filed by 30 of the plaintiffs. and is expected to dismiss additional lawsuits based on a recent ruling.Pre-trial motions and discovery are proceeding in the remaining cases and apre-trial scheduling order has been filed with the court. At this stage of the litigation, Generation and ComEd cannot estimate a range of loss, if any.
68th Street Dump.In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In March 2004, BGEconnection with BGE’s 2000 corporate restructuring the responsibility for this liability was transferred to Constellation and other PRPs formed the 68th Street Coalition and entered into consent order negotiations with the EPA
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
as a result of the 2012 Exelon and CEG merger is now Generation’s responsibility. In March 2004, the PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigateclean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and 19 of the PRPs including BGE, with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommendclean-up options. The PRPs submitted their investigation of the range ofclean-up options in the first quarter of 2011. Although the investigation and options provided to the U.S. EPA are still subject to U.S. EPA review and selection of a remedy, the range of estimatedclean-up costs to be allocated among all of the PRPs is in the range of $50 million to $64 million. On September 30, 2013, EPA issued the Record of Decision identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by EPA is consistent with the PRPs estimated range of costs noted above. A wholly owned subsidiary of Generation has agreed to indemnify BGE for most of the costs related to this settlement and clean-up of the site. Based on Generation’s preliminary review, it appears probable that Generation has liability and has established an appropriate accrual which are included in the table above for its share of the estimatedclean-up costs. costs which is included in the table above.
Rossville Ash Site. The Rossville Ash Site is a32-acre property located in Rosedale, Baltimore County, Maryland, which was used for the placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC (CPSG)., a wholly-owned subsidiary of Generation. In 2008, CPSG investigated and remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) to address any historic environmental concerns and ready the site for appropriate future redevelopment. The site was accepted into the program in 2010 and is currently going through the process to remediate the site and receive closure from MDE. GenerationExelon currently estimates the remaining cost to close the site to be approximately $6$4 million which has been fully reserved and included in the table above as of September 30, 2016.March 31, 2017.
Sauer Dump.On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs of $1.7 million for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRP’sPRPs signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which requires the PRP’sPRPs to conduct a remedial investigation (RI) and feasibility study (FS) at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. The ultimate outcome of this proceeding is uncertain. Since the U.S. EPA has not selected a cleanup remedy and the allocation of the cleanup costs among the PRPs has not been determined, BGE cannotan estimate of the range of loss.BGE’s reasonably possible loss, if any, cannot be determined. It is possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and BGE’s future results of operations and cash flows, and an appropriate accrual has been established and is included in the table above.
Riverside. In 2013, the MDE, at the request of EPA, conducted a site inspection and limited environmental sampling of certain portions of the 170 acre Riverside property owned by BGE. The site consists of several different parcels with different current and historical uses. The sampling included soil and groundwater samples for a number of potential environmental contaminants. The sampling confirmed the existence of contaminants consistent with the known historical uses of the various portions of the site. In March 2014, the MDE requested that BGE conduct an investigation which included a site-wide investigation of soils, sediment, groundwater, and surface water to complement the MDE sampling. The field investigation was completed in January 2015, and a final report was provided to MDE onin June 2, 2015. OnIn November 3, 2015, MDE provided BGE with its comments and recommendations on the report which require BGE to conduct further investigation and sampling at the site to better delineate the nature and extent of historic contamination, includingoff-site sediment and soil sampling. MDE did not request any interim remediation at this time and BGE anticipates completing the additional work requested by the end of the firstsecond quarter of 2017. BGE has established what it believes is an appropriate reserve based upon the investigation to date. The established reserve is included in the table above. As the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
investigation and potential remediation proceed, it is possible that additional reserves could be established, in amounts that could be material to BGE.
BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of the former MGP facility sites from customers; however, while BGE does not have a rider for MGPclean-up costs, BGE has historically received recovery of actualclean-up costs in distribution rates.
Benning Road Site. 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. The principal contaminants allegedly of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site.
The initial RI field work began in January 2013 and was completed in December 2014. In addition, in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the dismantled cooling towers for the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and, beginning in the third quarter of 2016, Pepco and Pepco Energy Services expect to implement a plan approved by DOEE to remove contaminated soil in conjunction with the demolition and removal of the concrete basins. On April 30, 2015, Pepco and Pepco Energy Services submitted a draft RI Report to DOEE. After review, DOEE determined that additional field investigation and data analysis iswas required to complete the RI process (much of which iswas beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services revised the draft RI Report to address DOEE’s comments and DOEE released the draft RI Report for public review onin February 29, 2016. The additional field investigation and data analysis will proceed later in 2016 according to a schedule to be developed by Pepco and Pepco Energy Services and approved by DOEE. Once the additional RI work has been completed, Pepco and Pepco Energy Services will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Pepco Energy Services will then proceed withto develop an FS to evaluate possible remedial alternatives. This effort also may includealternatives for submission to DOEE. The Court has established a treatability study to evaluateschedule for completion of the effectiveness of potential remedial options. OnceRI and FS, and approval by the FS evaluation has been completed, Pepco and Pepco Energy Services will prepare and submit a draft FS Report for review and commentDOEE, by DOEE and the public. Thereafter, Pepco and Pepco Energy Services will revise the draft FS Report as appropriate to address comments received and will submit a final FS Report to DOEE.June 2018.
Upon DOEE’s approval of the final remedial investigationRI and feasibility studyFS Reports, Pepco and Pepco Energy Services will have satisfied their obligations under the consent decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions based on the results of the remedial investigation and feasibility study.actions. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary.
PHI, Pepco and Pepco Energy Services have determined that a loss associated with this matter for PHI, Pepco and Pepco Energy Services is probable and an estimated liability for this issue has been accrued, which is included in the table above. As the remedial investigation proceeds and potential remedies are identified, it is possible that additional reservesaccruals could be established in amounts that could be material to PHI, Pepco and Pepco Energy Services. Pursuant to Exelon’s March 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation. The ultimate resolution of this matter is currently not expected to have any significant financial impact on Generation.
Anacostia River Tidal Reach.Reach. Contemporaneous with the Benning RI/FS being performed by Pepco and Pepco Energy Services, DOEE and certain federal agencies have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of theMaryland-D.C. boundary line to the confluence of the Anacostia and Potomac Rivers. In March 2016, DOEE released a draft of the river-wide RI
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
confluence of the Anacostia and Potomac Rivers. On March 18, 2016, DOEE released a draft of the river-wide RI Report for public review and comment. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a “Consultative Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road RI/FS. Pepco responded that it will participate in the Consultative Working Group but its participation is not an acceptance of any financial responsibility beyond the work that will be performed at the Benning Road site described above. On September 13, 2016 PHI attendedDOEE has advised the first Consultative Working Group meeting along with several other possible private and governmental PRP’s. At the meeting it was disclosed that the federal and DOEE authorities wereare conducting phase 2 of a remedial investigation,investigation. DOEE has targeted June 2018 as the date for remedy selection forclean-up of sediments in this section of the river. The Consultative Working Group and the other possible PRPs raised a number of issues withhave provided input into the proposedclean-up process and schedule. Several follow up meetings have been scheduled. At this time, it is not possible to predict the extent of Pepco’s participation in the river-wide RI/FS process, or its potential exposureand Pepco cannot estimate the reasonably possible range of loss for response costs beyond those associated with the Benning RI/FS component of the river-wide initiative. It is possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Pepco’s future results of operations and cash flows.
Conectiv Energy Wholesale Power Generation Sites. In July 2010, PHI sold the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required remediation activities at the 9 generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million, and PHI has established an appropriate accrual for its share of the estimatedclean-up costs, which is included in the table above. Pursuant to Exelon’s March 2016 acquisition of PHI, Conectiv Energy was transferred to Generation, however, the responsibility to indemnify Calpine remained at PHI. The ultimate resolution of this matter is currently not expected to have any significant financial impact on PHI.
Rock Creek Mineral Oil Release.In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release ofnon-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80% of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE, including the requirements of a February 29, 2016 compliance order which requires Pepco to prepare a full incident investigation report and prepare a removal action work plan to remove all impacted soils in the vicinity of the storm drain outfall, and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility.
To the extent recovery is available against any party who contributed to this loss, PHI and Pepco will pursue such action. Exelon, PHI and Pepco continue to investigate the cause of the incident, the parties involved, and
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
legal responsibility under District of Columbia law, but do not believe that the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Peck Iron and Metal Site. EPA informed Pepco in a May 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that the Peck Iron and Metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation on its belief that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In September 2011, EPA initiated a RI/FS for the site using Federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.
Brandywine Fly Ash Disposal Site. In February 2013, Pepco received a letter from the MDE requesting that Pepco investigate the extent of waste on a Pepcoright-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on theright-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.
Exelon, PHI and Pepco have determined that a loss associated with this matter is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million.million, for which an appropriate reserve has been established and is included in the table above. Exelon, PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.
Litigation and Regulatory Matters
Asbestos Personal Injury Claims (Exelon, Generation, ComEd, PECO and BGE)
Exelon, Generation and PECO. 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 reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material.
At September 30, 2016March 31, 2017 and December 31, 2015,2016, Generation had reserved approximately $83$82 million and $95$83 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2016,March 31, 2017, approximately $22$23 million of this amount related to 237240 open claims presented to Generation, while the remaining $61$59 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, 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 an adjustment to the reserve is necessary. During the nine months ended September 30, 2016, Generation decreased its reserve by approximately $8 million, primarily attributable to a continued decline in expected claims activity.
On November 22, 2013, the Supreme Court of Pennsylvania held that the Pennsylvania Workers Compensation Act does not apply to an employee’s disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee’s last employment-based exposure, and that therefore the exclusivity provision of the Act does not preclude such employee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the Pennsylvania Superior Court precluding current and former employees from suing their employers in court,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
despite the fact that the same employee was not eligible for workers compensation benefits for diseases that manifest more than 300 weeks after the employee’s last employment-based exposure to asbestos. Since the Pennsylvania Supreme Court’s ruling in November 2013, Exelon, Generation, and PECO have experienced an increase in asbestos-related personal injury claims brought by former PECO employees, all of which have been reserved for on a claim by claim basis. Those additional claims are taken into account in projecting estimates of future asbestos-related bodily injury claims.
On November 4, 2015, the Illinois Supreme Court found that the provisions of the Illinois’ Workers’ Compensation Act and the Workers’ Occupational Diseases Act barred an employee from bringing a direct civil
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
action against an employer for latent diseases, including asbestos-related diseases that fall outside the25-year limit of the statute of repose. The Illinois Supreme Court’s ruling reversed previous rulings by the Illinois Court of Appeals, which initially ruled that the Illinois Worker’s Compensation law should not apply in cases where the diagnosis of an asbestos related disease occurred after the25-year maximum time period for filing a Worker’s Compensation claim. Since the Illinois Supreme Court’s ruling in November 2015, Exelon, Generation, and ComEd have not experienced a significant increase in asbestos-related personal injury claims brought by former ComEd employees.
There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued and the increases could have a material adverse effect on Exelon’s, Generation’s, ComEd’s, PECO and BGE’s future results of operations and cash flows.
BGE. Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of “premises liability,” alleging that BGE and Generation knew of and exposed individuals to an asbestos hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases.
Approximately 456 individuals who were never employees of BGE or certain Constellation subsidiaries have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and certain Constellation subsidiaries in these actions. To date, most asbestos claims which have been resolved relating to BGE and certain Constellation subsidiaries have been dismissed or resolved without any payment by BGE or certain Constellation subsidiaries and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results.
Discovery begins in these Presently, there are an immaterial number of asbestos cases after they are placed on the trial docket. Given the limited discovery in these cases,pending against BGE and Generation do not know the specific facts that are necessary to provide an estimate of the reasonably possible loss relating to these claims; as such, no accrual has been made and a range of loss is not estimable. The specific facts not known include:
the identity of the facilities at which the plaintiffs allegedly worked as contractors;
the names of the plaintiffs’ employers;
the dates on which and the places where the exposure allegedly occurred; and
the facts and circumstances relating to the alleged exposure.
Insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
certain Constellation subsidiaries.
Continuous Power Interruption (Exelon and ComEd)
Section 16-125 of the Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) more than 30,000 customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law. As of September 30, 2016March 31, 2017 and December 31, 2015,2016, ComEd did not have any material liabilities recorded for these storm events.
Baltimore City Franchise Taxes (Exelon and BGE)
The City of Baltimore claims that BGE has maintained electric facilities in the City’s publicright-of-ways for over one hundred years without the proper franchise rights from the City. BGE has reviewed the City’s claim and believes that it lacks merit. BGE has not recorded an accrual for payment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future periods may be material to BGE’s results of operations and cash flows.
Conduit Lease with City of Baltimore (Exelon and BGE)
On September 23, 2015, the Baltimore City Board of Estimates approved an increase in annual rental fees for access to the Baltimore City underground conduit system effective November 1, 2015, from $12 million to $42 million, subject to an annual increase thereafter based on the Consumer Price Index. BGE subsequently entered into litigation with the City regarding the amount of and basis for establishing the conduit fee. On November 30, 2016, the Baltimore City Board of Estimates approved a settlement agreement entered into
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
between BGE and the City to resolve the disputes and pending litigation related to BGE’s use of and payment for the underground conduit system. As a result of the settlement, the parties have entered into asix-year lease that reduces the annual expense to $25 million in the first three years and caps the annual expense in the last three years to not more than $29 million. BGE recorded a credit to Operating and maintenance expense in the fourth quarter of approximately $28 million for the reversal of the previously higher fees accrued in the current year as well as the settlement of prior year disputed feetrue-up amounts.
Deere Wind Energy Assets (Exelon and Generation)
In 2013, Deere & Company (“Deere”) filed a lawsuit against Generation in the Delaware Superior Court relating to Generation’s acquisition of the Deere wind energy assets. Under the purchase agreement, Deere was entitled to receiveearn-out payments if certain specific wind projects already under development in Michigan met certain development and construction milestones following the sale. In the complaint, Deere seeks to recover a $14 millionearn-out payment associated with one such project, which was never completed. Generation has filed counterclaims against Deere for breach of contract, with a right of recoupment and set off. On June 2, 2016, the Delaware Superior Court entered summary judgment in favor of Deere. On January 17, 2017, Generation is reviewingfiled an appeal of the Superior Court’s summary judgment decision and determining whether to appeal towith the Delaware Supreme Court.Court of Delaware. Generation has accrued an amount to cover its potential liability.
General (All Registrants)
The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, 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.
Income Taxes(Exelon, Generation, ComEd, PECO and BGE)
See Note 11 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
19.18. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2016March 31, 2017 and 2015:2016.
Three Months Ended September 30, 2016 | Three Months Ended March 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other, Net | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net realized income on decommissioning trust funds(a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory agreement units | $ | 57 | $ | 57 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 68 | $ | 68 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||
Non-regulatory agreement units | 35 | 35 | — | — | — | — | — | — | — | 32 | 32 | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net unrealized gains on decommissioning trust funds | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory agreement units | 155 | 155 | — | — | — | — | — | — | — | 222 | 222 | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Non-regulatory agreement units | 116 | 116 | — | — | — | — | — | — | — | 166 | 166 | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net unrealized losses on pledged assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Zion Station decommissioning | (5 | ) | (5 | ) | — | — | — | — | — | — | — | (1 | ) | (1 | ) | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | (168 | ) | (168 | ) | — | — | — | — | — | — | — | (234 | ) | (234 | ) | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
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Total decommissioning-related activities | 190 | 190 | — | — | — | — | — | — | — | 253 | 253 | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Investment income | 2 | 1 | — | (1 | ) | — | — | — | — | — | 2 | 2 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest income related to uncertain income tax positions | 8 | — | — | — | — | — | — | — | — | 1 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Penalty related to uncertain income tax positions(c) | (106 | ) | — | (86 | ) | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
AFUDC — Equity | 19 | — | 5 | 2 | 5 | 7 | 5 | 1 | 1 | 17 | — | 2 | 2 | 4 | 9 | 5 | 2 | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other | 7 | (6 | ) | 1 | 1 | — | 12 | 7 | 2 | 1 | 10 | 4 | 2 | — | — | 4 | 3 | 1 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||
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Other, net | $ | 120 | $ | 185 | $ | (80 | ) | $ | 2 | $ | 5 | $ | 19 | $ | 12 | $ | 3 | $ | 2 | $ | 283 | $ | 259 | $ | 4 | $ | 2 | $ | 4 | $ | 13 | $ | 8 | $ | 3 | $ | 2 | |||||||||||||||||||||||||||||||||||
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Nine Months Ended September 30, 2016 | March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | Three Months Ended March 31, 2016 | March 24, 2016 to March 31, 2016 | January 1, 2016 to March 23, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL | ACE | PHI | PHI | Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL | ACE | PHI | PHI | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other, Net | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net realized income on decommissioning trust funds(a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory agreement units | $ | 181 | $ | 181 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 34 | $ | 34 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Non-regulatory agreement units | 95 | 95 | — | — | — | — | — | — | — | — | 21 | 21 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net unrealized gains on decommissioning trust funds | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory agreement units | 286 | 286 | — | — | — | — | — | — | — | — | 79 | 79 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Non-regulatory agreement units | 216 | 216 | — | — | — | — | — | — | — | — | 52 | 52 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net unrealized losses on pledged assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Zion Station decommissioning | (2 | ) | (2 | ) | — | — | — | — | — | — | — | — | 2 | 2 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | (380 | ) | (380 | ) | — | — | — | — | — | — | — | — | (95 | ) | (95 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total decommissioning-related activities | 396 | 396 | — | — | — | — | — | — | — | — | 93 | 93 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Investment income (expense) | 14 | 6 | — | (1 | ) | 2 | (d) | — | — | — | 1 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Investment income | 6 | 1 | — | — | 1 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term lease income | 4 | — | — | — | — | — | — | — | — | — | 4 | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest income related to uncertain income tax positions | 13 | — | — | — | — | 1 | — | 1 | — | — | 1 | — | — | — | — | 1 | — | 1 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Penalty income related to uncertain income tax positions(c) | (106 | ) | — | (86 | ) | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
AFUDC — Equity | 43 | — | 8 | 6 | 14 | 14 | 3 | 5 | 15 | 7 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
AFUDC—Equity | 8 | — | 2 | 2 | 3 | 4 | 1 | 2 | 1 | 7 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Loss on debt extinguishment | (3 | ) | (2 | ) | — | — | — | — | — | — | — | — | (2 | ) | (2 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other | 16 | (5 | ) | 6 | 1 | — | 13 | 6 | 2 | 15 | (11 | ) | 4 | 1 | 2 | — | — | 4 | 2 | 1 | 1 | (11 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Other, net | $ | 377 | $ | 395 | $ | (72 | ) | $ | 6 | $ | 16 | $ | 28 | $ | 9 | $ | 8 | $ | 31 | $ | (4 | ) | $ | 114 | $ | 93 | $ | 4 | $ | 2 | $ | 4 | $ | 9 | $ | 3 | $ | 4 | $ | 2 | $ | (4 | ) | |||||||||||||||||||||||||||||||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Three Months Ended September 30, 2015 | ||||||||||||||||||||||||||||||||||||
Predecessor | ||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||
Other, Net | ||||||||||||||||||||||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||||||||||||||||||||||
Net realized income on decommissioning trust funds(a) | ||||||||||||||||||||||||||||||||||||
Regulatory agreement units | $ | 39 | $ | 39 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||
Non-regulatory agreement units | 18 | 18 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Net unrealized losses on decommissioning trust funds | ||||||||||||||||||||||||||||||||||||
Regulatory agreement units | (301 | ) | (301 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||
Non-regulatory agreement units | (218 | ) | (218 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | 207 | 207 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
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Total decommissioning-related activities | (255 | ) | (255 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||
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Investment income (expense) | 4 | 1 | — | (1 | ) | 1 | (d) | — | — | — | — | |||||||||||||||||||||||||
Long-term lease income | 4 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
AFUDC — Equity | 6 | — | 1 | 1 | 4 | 2 | 3 | — | — | |||||||||||||||||||||||||||
Other | (3 | ) | (3 | ) | 3 | 1 | (1 | ) | 25 | 5 | 4 | 1 | ||||||||||||||||||||||||
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Other, net | $ | (244 | ) | $ | (257 | ) | $ | 4 | $ | 1 | $ | 4 | $ | 27 | $ | 8 | $ | 4 | $ | 1 | ||||||||||||||||
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Nine Months Ended September 30, 2015 | ||||||||||||||||||||||||||||||||||||
Predecessor | ||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||
Other, Net | ||||||||||||||||||||||||||||||||||||
Decommissioning-related activities: | ||||||||||||||||||||||||||||||||||||
Net realized income on decommissioning trust funds(a) | ||||||||||||||||||||||||||||||||||||
Regulatory agreement units | $ | 203 | $ | 203 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||
Non-regulatory agreement units | 122 | 122 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Net unrealized losses on decommissioning trust funds | ||||||||||||||||||||||||||||||||||||
Regulatory agreement units | (385 | ) | (385 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||
Non-regulatory agreement units | (274 | ) | (274 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||
Net unrealized gains on pledged assets | ||||||||||||||||||||||||||||||||||||
Zion Station decommissioning | 9 | 9 | — | — | — | — | — | — | ||||||||||||||||||||||||||||
Regulatory offset to decommissioning trust fund-related activities(b) | 129 | 129 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
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Total decommissioning-related activities | (196 | ) | (196 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||
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Investment income (expense) | 6 | 1 | — | (1 | ) | 3 | (d) | — | — | — | — | |||||||||||||||||||||||||
Long-term lease income | 12 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Interest income related to uncertain income tax positions | — | 1 | — | — | — | — | — | — | 1 | |||||||||||||||||||||||||||
AFUDC — Equity | 16 | — | 2 | 4 | 10 | 11 | 9 | 1 | 1 | |||||||||||||||||||||||||||
Terminated interest rate swaps(e) | (26 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||
Other | 9 | 1 | 12 | — | — | 37 | 12 | 7 | 2 | |||||||||||||||||||||||||||
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Other, net | $ | (179 | ) | $ | (193 | ) | $ | 14 | $ | 3 | $ | 13 | $ | 48 | $ | 21 | $ | 8 | $ | 4 | ||||||||||||||||
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(a) | Includes investment income and realized gains and losses on sales of investments of the trust funds. |
(b) | Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 16 — Asset Retirement Obligations of the Exelon |
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following utility taxes are included in revenues and expenses for the three and nine months ended September 30, 2016March 31, 2017 and 2015.2016. Generation’s utility tax expense represents gross receipts tax related to its retail operations, and the utility registrants’ utility tax expense 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 on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Three Months Ended September 30, 2016 | ||||||||||||||||||||||||||||||||||||
Successor | ||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||
Utility taxes | $ | 255 | $ | 35 | $ | 67 | $ | 40 | $ | 21 | $ | 92 | $ | 87 | $ | 5 | $ | — |
Three Months Ended March 31, 2017 | ||||||||||||||||||||||||||||||||||||
Successor | ||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||
Utility taxes | $ | 224 | $ | 32 | $ | 59 | $ | 31 | $ | 26 | $ | 76 | $ | 71 | $ | 5 | $ | — |
Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2016 | March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | ||||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL | ACE | PHI | PHI | |||||||||||||||||||||||||||||||
Utility taxes | $ | 624 | $ | 90 | $ | 186 | $ | 106 | $ | 66 | $ | 240 | $ | 14 | $ | — | $ | 176 | $ | 78 |
Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, 2016 | March 24, 2016 to March 31, 2016 | January 1, 2016 to March 23, 2016 | ||||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL | ACE | PHI | PHI | |||||||||||||||||||||||||||||||
Utility taxes | $ | 153 | $ | 28 | $ | 59 | $ | 35 | $ | 24 | $ | 79 | $ | 5 | $ | — | $ | 7 | $ | 77 |
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the three months ended March 31, 2017 and 2016.
Three Months Ended September 30, 2015 | ||||||||||||||||||||||||||||||||||||
Predecessor | ||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||
Utility taxes | $ | 151 | $ | 28 | $ | 63 | $ | 37 | $ | 23 | $ | 86 | $ | 82 | $ | 4 | $ | — |
Nine Months Ended September 30, 2015 | ||||||||||||||||||||||||||||||||||||
Predecessor | ||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||
Utility taxes | $ | 430 | $ | 79 | $ | 180 | $ | 104 | $ | 67 | $ | 253 | $ | 239 | $ | 14 | $ | — |
Three Months Ended March 31, 2017 | ||||||||||||||||||||||||||||||||||||
Successor | ||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||||||||||||||||||||||
Property, plant and equipment(a) | $ | 754 | $ | 289 | $ | 190 | $ | 64 | $ | 80 | $ | 112 | $ | 50 | $ | 30 | $ | 21 | ||||||||||||||||||
Amortization of regulatory assets(a) | 128 | — | 18 | 7 | 48 | 55 | 32 | 9 | 14 | |||||||||||||||||||||||||||
Amortization of intangible assets, net(a) | 14 | 13 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Amortization of energy contract assets and liabilities(b) | 2 | 2 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Nuclear fuel(c) | 264 | 264 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
ARO accretion(d) | 112 | 110 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
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Total depreciation, amortization and accretion | $ | 1,274 | $ | 678 | $ | 208 | $ | 71 | $ | 128 | $ | 167 | $ | 82 | $ | 39 | $ | 35 | ||||||||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015:
Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2016 | March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | ||||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL | ACE | PHI | PHI | |||||||||||||||||||||||||||||||
Depreciation, amortization, accretion and depletion | ||||||||||||||||||||||||||||||||||||||||
Property, plant and equipment(a) | $ | 2,490 | $ | 1,297 | $ | 524 | $ | 181 | $ | 223 | $ | 128 | $ | 82 | $ | 61 | $ | 215 | $ | 94 | ||||||||||||||||||||
Amortization of regulatory assets(a) | 293 | — | 49 | 20 | 84 | 93 | 38 | 69 | 140 | 58 | ||||||||||||||||||||||||||||||
Amortization of intangible assets, net(a) | 38 | 32 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Amortization of energy contract assets and liabilities(b) | (7 | ) | (7 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
Nuclear fuel(c) | 862 | 862 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
ARO accretion(d) | 333 | 332 | 1 | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
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Total depreciation, amortization, accretion and depletion | $ | 4,009 | $ | 2,516 | $ | 574 | $ | 201 | $ | 307 | $ | 221 | $ | 120 | $ | 130 | $ | 355 | $ | 152 | ||||||||||||||||||||
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Nine Months Ended September 30, 2015 | Successor | Predecessor | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Predecessor | Three Months Ended March 31, 2016 | March 24, 2016 to March 31, 2016 | January 1, 2016 to March 23, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL | ACE | PHI | PHI | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Depreciation, amortization, accretion and depletion | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Depreciation, amortization and accretion | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, plant and equipment(a) | $ | 1,648 | $ | 739 | $ | 471 | $ | 179 | $ | 216 | $ | 292 | $ | 122 | $ | 76 | $ | 57 | $ | 606 | $ | 278 | $ | 170 | $ | 60 | $ | 75 | $ | 42 | $ | 27 | $ | 20 | $ | 9 | $ | 94 | ||||||||||||||||||||||||||||||||||||||
Amortization of regulatory assets(a) | 131 | — | 57 | 19 | 55 | 182 | 69 | 37 | 78 | 65 | — | 19 | 7 | 34 | 33 | 12 | 20 | 5 | 58 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization of intangible assets, net(a) | 39 | 35 | — | — | — | — | — | — | — | 14 | 11 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization of energy contract assets and liabilities(b) | (20 | ) | (19 | ) | — | — | — | — | — | — | — | (14 | ) | (14 | ) | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear fuel(c) | 841 | 841 | — | — | — | — | — | — | — | 283 | 283 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
ARO accretion(d) | 291 | 291 | — | — | — | — | — | — | — | 109 | 109 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total depreciation, amortization, accretion and depletion | $ | 2,930 | $ | 1,887 | $ | 528 | $ | 198 | $ | 271 | $ | 474 | $ | 191 | $ | 113 | $ | 135 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total depreciation, amortization and accretion | $ | 1,063 | $ | 667 | $ | 189 | $ | 67 | $ | 109 | $ | 75 | $ | 39 | $ | 40 | $ | 14 | $ | 152 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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(a) | Included in Depreciation and amortization on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
(b) | Included in Operating revenues or Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
(c) | Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
(d) | Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
Three Months Ended March 31, 2017 | ||||||||||||||||||||||||||||||||||||
Successor | ||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||
Othernon-cash operating activities: | ||||||||||||||||||||||||||||||||||||
Pension andnon-pension postretirement benefit costs | $ | 157 | $ | 54 | $ | 44 | $ | 7 | $ | 16 | $ | 24 | $ | 7 | $ | 3 | $ | 3 | ||||||||||||||||||
Loss from equity method investments | 10 | 10 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Provision for uncollectible accounts | 34 | 9 | 7 | 17 | 5 | (4 | ) | (5 | ) | (1 | ) | 1 | ||||||||||||||||||||||||
Stock-based compensation costs | 31 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Other decommissioning-related activity(a) | (84 | ) | (84 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||
Energy-related options(b) | (4 | ) | (4 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||
Amortization of regulatory asset related to debt costs | 2 | — | 1 | — | — | 1 | — | — | — | |||||||||||||||||||||||||||
Amortization of rate stabilization deferral | (14 | ) | — | — | — | 7 | (21 | ) | (15 | ) | (6 | ) | — | |||||||||||||||||||||||
Amortization of debt fair value adjustment | (5 | ) | (3 | ) | — | — | — | (2 | ) | — | — | — | ||||||||||||||||||||||||
Discrete impacts from EIMA(c) | (24 | ) | — | (24 | ) | — | — | — | — | — | — | |||||||||||||||||||||||||
Amortization of debt costs | 9 | 4 | 1 | — | — | — | — | — | — | |||||||||||||||||||||||||||
Provision for excess and obsolete inventory | 2 | 1 | 1 | — | — | — | — | — | — | |||||||||||||||||||||||||||
Other | 4 | 3 | 1 | (1 | ) | (4 | ) | (6 | ) | (2 | ) | (3 | ) | (2 | ) | |||||||||||||||||||||
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Total othernon-cash operating activities | $ | 118 | $ | (10 | ) | $ | 31 | $ | 23 | $ | 24 | $ | (8 | ) | $ | (15 | ) | $ | (7 | ) | $ | 2 | ||||||||||||||
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Non-cash investing and financing activities: |
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Change in capital expenditures not paid | $ | (298 | ) | $ | (354 | ) | $ | 25 | $ | — | $ | 41 | $ | (5 | ) | $ | (6 | ) | $ | 9 | $ | — | ||||||||||||||
Non-cash financing of capital projects | 10 | 10 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
Dividends on stock compensation | 2 | — | — | — | — | — | — | — | — |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2016 | March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | ||||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL | ACE | PHI | PHI | |||||||||||||||||||||||||||||||
Other non-cash operating activities: | ||||||||||||||||||||||||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 458 | $ | 163 | $ | 124 | $ | 25 | $ | 50 | $ | 24 | $ | 13 | $ | 11 | $ | 58 | $ | 23 | ||||||||||||||||||||
Loss from equity method investments | 15 | 16 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Provision for uncollectible accounts | 107 | 14 | 31 | 24 | 12 | 15 | 12 | 18 | 27 | 16 | ||||||||||||||||||||||||||||||
Stock-based compensation costs | 88 | — | — | — | — | — | — | — | — | 3 | ||||||||||||||||||||||||||||||
Other decommissioning-related activity(a) | (237 | ) | (237 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
Energy-related options(b) | (20 | ) | (20 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
Amortization of regulatory asset related to debt costs | 7 | — | 3 | 1 | — | 2 | — | 1 | 2 | 1 | ||||||||||||||||||||||||||||||
Amortization of rate stabilization deferral | 62 | — | — | — | 62 | 3 | 3 | — | — | 5 | ||||||||||||||||||||||||||||||
Amortization of debt fair value adjustment | (9 | ) | (9 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
Discrete impacts from EIMA(c) | (36 | ) | — | (36 | ) | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
Amortization of debt costs | 26 | 12 | (3 | ) | 2 | 3 | — | — | — | — | — | |||||||||||||||||||||||||||||
Provision for excess and obsolete inventory | 74 | 70 | 4 | — | — | 1 | 1 | 1 | — | 1 | ||||||||||||||||||||||||||||||
Merger-related commitments(d)(e) | 508 | 3 | — | — | — | 125 | 73 | 110 | 308 | — | ||||||||||||||||||||||||||||||
Severance costs | 130 | 57 | — | — | — | — | — | — | 53 | — | ||||||||||||||||||||||||||||||
Asset retirement costs | — | — | — | — | — | — | 5 | 2 | — | — | ||||||||||||||||||||||||||||||
Lower of cost or market inventory adjustment | 36 | 36 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Other | 15 | 24 | (1 | ) | (3 | ) | (18 | ) | (2 | ) | (8 | ) | (5 | ) | (7 | ) | (3 | ) | ||||||||||||||||||||||
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Total other non-cash operating activities | $ | 1,224 | $ | 129 | $ | 122 | $ | 49 | $ | 109 | $ | 168 | $ | 99 | $ | 138 | $ | 441 | $ | 46 | ||||||||||||||||||||
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Non-cash investing and financing activities: | ||||||||||||||||||||||||||||||||||||||||
Change in capital expenditures not paid | $ | (338 | ) | $ | (289 | ) | $ | (42 | ) | $ | (4 | ) | $ | 17 | $ | 15 | $ | (10 | ) | $ | 2 | $ | (5 | ) | $ | 11 | ||||||||||||||
Fair value of net assets contributed to Generation in connection with the PHI merger, net of cash(d)(f) | — | 119 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash(d)(f) | — | — | — | — | — | — | — | — | 129 | — | ||||||||||||||||||||||||||||||
Fair value of pension obligation transferred in connection with the PHI Merger | — | — | — | — | — | — | — | — | 53 | — | ||||||||||||||||||||||||||||||
Assumption of member purchase liability | — | — | — | — | — | — | — | — | 29 | — | ||||||||||||||||||||||||||||||
Assumption of merger commitment liability | — | — | — | — | — | 33 | — | — | 33 | — | ||||||||||||||||||||||||||||||
Change in PPE related to ARO update | 476 | 476 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Indemnification of like-kind exchange position(g) | — | — | 157 | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Non-cash financing of capital projects | 84 | 84 | — | — | — | — | — | — | — | — |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Nine Months Ended September 30, 2015 | Successor | Predecessor | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Predecessor | Three Months Ended March 31, 2016 | March 24, 2016 to March 31, 2016 | January 1, 2016 to March 23, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL | ACE | PHI | PHI | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other non-cash operating activities: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 476 | $ | 200 | $ | 155 | $ | 29 | $ | 49 | $ | 73 | $ | 22 | $ | 11 | $ | 11 | $ | 136 | $ | 54 | $ | 41 | $ | 8 | $ | 16 | $ | 8 | $ | 5 | $ | 4 | $ | 3 | $ | 23 | ||||||||||||||||||||||||||||||||||||||
Loss from equity method investments | 3 | 4 | — | — | — | — | — | — | — | 3 | 3 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Provision for uncollectible accounts | 114 | 15 | 46 | 37 | 15 | 49 | 15 | 18 | 15 | 41 | 6 | 9 | 16 | 12 | 5 | 5 | 7 | (2 | ) | 16 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stock-based compensation costs | 102 | — | — | — | — | 9 | — | — | — | 44 | — | — | — | — | — | — | — | — | 3 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other decommissioning-related activity(a) | (31 | ) | (31 | ) | — | — | — | — | — | — | — | (55 | ) | (55 | ) | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy-related options(b) | 18 | 18 | — | — | — | — | — | — | — | (9 | ) | (9 | ) | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization of regulatory asset related to debt costs | — | — | — | — | — | 4 | 2 | — | — | 1 | — | 1 | — | — | 1 | — | — | — | 1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization of rate stabilization deferral | 60 | — | — | — | 60 | 3 | 3 | 1 | — | 20 | — | — | — | 20 | 1 | 4 | — | — | 5 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization of debt fair value adjustment | (34 | ) | (9 | ) | — | — | — | — | — | — | — | (3 | ) | (3 | ) | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Discrete impacts from EIMA(c) | 101 | — | 101 | — | — | — | — | — | — | (14 | ) | — | (14 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization of debt costs | 43 | 12 | 3 | 2 | 2 | 1 | — | — | — | 8 | 4 | 1 | 1 | 1 | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Provision for excess and obsolete inventory | 7 | 8 | — | — | — | 1 | — | — | — | 1 | 1 | — | — | — | 1 | 1 | 1 | — | 1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Lower of cost or market inventory adjustment | 15 | 15 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Merger-related commitments(d)(e) | 503 | 3 | — | — | — | 138 | 100 | 120 | 358 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Severance costs | 69 | 4 | — | — | — | — | — | — | 52 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset retirement costs | — | — | — | — | — | — | 4 | 2 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Lower of cost or net realizable value inventory adjustment | 36 | 36 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other | (18 | ) | (5 | ) | 7 | 1 | (15 | ) | 3 | — | 1 | 1 | 23 | 7 | (6 | ) | (1 | ) | (5 | ) | (1 | ) | (1 | ) | (2 | ) | (1 | ) | (3 | ) | ||||||||||||||||||||||||||||||||||||||||||||||
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Total other non-cash operating activities | $ | 856 | $ | 227 | $ | 312 | $ | 69 | $ | 111 | $ | 143 | $ | 42 | $ | 31 | $ | 27 | $ | 804 | $ | 51 | $ | 32 | $ | 24 | $ | 44 | $ | 153 | $ | 118 | $ | 132 | $ | 410 | $ | 46 | ||||||||||||||||||||||||||||||||||||||
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Non-cash investing and financing activities: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Change in capital expenditures not paid | $ | 59 | $ | 48 | $ | 62 | $ | (23 | ) | $ | (14 | ) | $ | (3 | ) | $ | (1 | ) | $ | 2 | $ | — | $ | (290 | ) | $ | (234 | ) | $ | 25 | $ | (65 | ) | $ | (4 | ) | $ | 9 | $ | 8 | $ | (9 | ) | $ | (7 | ) | $ | 11 | ||||||||||||||||||||||||||||
Nuclear fuel procurement(d) | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash(d)(f) | — | 119 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash(d)(f) | — | — | — | — | — | — | — | — | 127 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of pension obligation transferred in connection with the PHI Merger | — | — | — | — | — | — | — | — | 45 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Assumption of member purchase liability | — | — | — | — | — | — | — | — | 29 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Change in PPE related to ARO update | 811 | 811 | — | — | — | — | — | — | — | 62 | 62 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Indemnification of like-kind exchange position(g) | — | — | 5 | — | — | — | — | — | — | — | — | 1 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Non-cash financing of capital projects | 52 | 52 | — | — | — | — | — | — | — | 31 | 31 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term software licensing agreement(f) | 95 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dividends on stock compensation | 1 | — | — | — | — | — | — | — | — | — |
(a) | Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 16 — Asset Retirement Obligations of the Exelon |
(b) | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded in Operating revenues. |
(c) | Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through apre-established performance-based formula rate tariff. See Note 5 — Regulatory Matters for more information. |
(d) | See Note 4 — Mergers, Acquisitions and Dispositions for additional information related to the merger with PHI. |
(e) | Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts. |
(f) | Immediately following closing of the PHI Merger, the net assets associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation. |
(g) | See Note 11 — Income Taxes for discussion of the like-kind exchange tax position. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 2016March 31, 2017 and December 31, 2015:2016.
Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
September 30, 2016 | Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
March 31, 2017 | Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, plant and equipment: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accumulated depreciation and amortization | $ | 18,354 | (a) | $ | 10,004 | (a) | $ | 3,841 | $ | 3,213 | $ | 3,198 | $ | 146 | $ | 3,026 | $ | 1,171 | $ | 1,008 | $ | 19,716 | (a) | $ | 10,801 | (a) | $ | 4,040 | $ | 3,293 | $ | 3,311 | $ | 281 | $ | 3,090 | $ | 1,195 | $ | 1,032 | ||||||||||||||||||||||||||||||||
Accounts receivable: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts | $ | 330 | $ | 85 | $ | 82 | $ | 78 | $ | 39 | $ | 46 | $ | 15 | $ | 14 | $ | 17 | $ | 346 | $ | 97 | $ | 80 | $ | 72 | $ | 35 | $ | 61 | $ | 18 | $ | 20 | $ | 23 | ||||||||||||||||||||||||||||||||||||
Predecessor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2015 | Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2016 | Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, plant and equipment: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accumulated depreciation and amortization | $ | 16,375 | (b) | $ | 8,639 | (b) | $ | 3,710 | $ | 3,101 | $ | 3,016 | $ | 5,341 | $ | 2,929 | $ | 1,139 | $ | 968 | $ | 19,169 | (b) | $ | 10,562 | (b) | $ | 3,937 | $ | 3,253 | $ | 3,254 | $ | 195 | $ | 3,050 | $ | 1,175 | $ | 1,016 | ||||||||||||||||||||||||||||||||
Accounts receivable: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts | $ | 284 | $ | 77 | $ | 75 | $ | 83 | $ | 49 | $ | 56 | $ | 17 | $ | 17 | $ | 17 | $ | 334 | $ | 91 | $ | 70 | $ | 61 | $ | 32 | $ | 80 | $ | 29 | $ | 24 | $ | 27 |
(a) | Includes accumulated amortization of nuclear fuel in the reactor core of |
(b) | Includes accumulated amortization of nuclear fuel in the reactor core of |
PECO Installment Plan Receivables (Exelon and PECO)
PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $16$9 million and $15$9 million as of September 30, 2016March 31, 2017 and December 31, 2015,2016, respectively. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 20152016 Form10-K. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2016March 31, 2017 of $14$11 million consists of $0 million, $3 million and $11$8 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 20152016 of $15$13 million consists of $1 million, $3 million and $11$9 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of September 30, 2016March 31, 2017 and December 31, 20152016 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 20152016 Form10-K.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
20.19. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to evaluate performance and allocate resources at each of the Registrants.
In the first quarter of 2016, following the consummation of the PHI Merger, three new reportable segments were added: Pepco, DPL and ACE. As a result, Exelon has twelve reportable segments, which include ComEd, PECO, BGE, PHI’s three reportable segments consisting of Pepco, DPL, and ACE, and Generation’s six power marketing reportable segments consisting of theMid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”, which includes activities in the South, West and Canada. 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 and return on equity.
Effective with the consummation of the PHI Merger, PHI’s reportable segments have changed based on the information used by the CODM to evaluate performance and allocate resources. PHI’s reportable segments consist of Pepco, DPL and ACE. PHI’s Predecessor periods’ segment information has been recast to conform to the current presentation. The reclassification of the segment information did not impact PHI’s reported consolidated revenues or net income. PHI’s CODM evaluates the performance of and allocates resources to Pepco, DPL and ACE based on net income and return on equity.
The basis for Generation’s reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation’s hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of Generation’s six reportable segments are as follows:
• | Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina. |
• | Midwest represents operations in the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky. |
• | New England represents the operations withinISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. |
• | New York represents operations withinISO-NY, which covers the state of New York in its entirety. |
• | ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas. |
• | Other Power Regions: |
• | South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas. |
• | West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado and parts of New Mexico, Wyoming and South Dakota. |
• | 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 power marketingelectric business activities and allocate resources based on revenuerevenues net of purchased power and fuel expense (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 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 unrealizedmark-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 not included inexcluded 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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,March 31, 2017 and 2016 and 2015 is as follows:
Three Months Ended September 30,March 31, 2017 and 2016 and 2015
Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Generation(a) | ComEd | PECO | BGE | PHI(b) | Other(c) | Intersegment Eliminations | Exelon | Generation(a) | ComEd | PECO | BGE | PHI(b) | Other(c) | Intersegment Eliminations | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||||
Operating revenues(d): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Competitive businesses electric revenues | $ | 3,720 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (328 | ) | $ | 3,392 | |||||||||||||||||||||||||||||||||||||||||||||||
Competitive businesses natural gas revenues | 918 | — | — | — | — | — | — | 918 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Competitive businesses other revenues | 250 | — | — | — | — | — | — | 250 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate-regulated electric revenues | — | 1,298 | 590 | 667 | 1,097 | — | (8 | ) | 3,644 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate-regulated natural gas revenues | — | — | 206 | 284 | 66 | — | (3 | ) | 553 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Shared service and other revenues | — | — | — | — | 12 | 419 | (431 | ) | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Competitive businesses electric revenues | $ | 4,322 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (499 | ) | $ | 3,823 | $ | 3,695 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (266 | ) | $ | 3,429 | ||||||||||||||||||||||||||||||
Competitive businesses natural gas revenues | 326 | — | — | — | — | — | — | 326 | 822 | — | — | — | — | — | — | 822 | ||||||||||||||||||||||||||||||||||||||||||||||||
Competitive businesses other revenues | 387 | — | — | — | — | — | (1 | ) | 386 | 222 | — | — | — | — | — | — | 222 | |||||||||||||||||||||||||||||||||||||||||||||||
Rate-regulated electric revenues | — | 1,497 | 740 | 735 | 1,366 | — | (8 | ) | 4,330 | — | 1,249 | 644 | 680 | 90 | — | (6 | ) | 2,657 | ||||||||||||||||||||||||||||||||||||||||||||||
Rate-regulated natural gas revenues | — | — | 48 | 77 | 17 | — | (5 | ) | 137 | — | — | 197 | 249 | 3 | — | (5 | ) | 444 | ||||||||||||||||||||||||||||||||||||||||||||||
Shared service and other revenues | — | — | — | — | 11 | 362 | (373 | ) | — | — | — | — | — | 12 | 405 | (418 | ) | (1 | ) | |||||||||||||||||||||||||||||||||||||||||||||
2015 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Competitive businesses electric revenues | $ | 4,299 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (204 | ) | $ | 4,095 | |||||||||||||||||||||||||||||||||||||||||||||||
Competitive businesses natural gas revenues | 347 | — | — | — | — | — | — | 347 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Competitive businesses other revenues | 122 | — | — | — | — | — | — | 122 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate-regulated electric revenues | — | 1,376 | 691 | 655 | — | — | (1 | ) | 2,721 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate-regulated natural gas revenues | — | — | 49 | 70 | — | — | (3 | ) | 116 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Shared service and other revenues | — | — | — | — | — | 348 | (348 | ) | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Intersegment revenues(e): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2017 | $ | 328 | $ | 5 | $ | 1 | $ | 5 | $ | 12 | $ | 419 | $ | (770 | ) | $ | — | |||||||||||||||||||||||||||||||||||||||||||||||
2016 | $ | 500 | $ | 4 | $ | 2 | $ | 7 | $ | 11 | $ | 362 | $ | (885 | ) | $ | 1 | 266 | 5 | 1 | 5 | 12 | 405 | (695 | ) | (1 | ) | |||||||||||||||||||||||||||||||||||||
2015 | 205 | 1 | 1 | 3 | — | 347 | (555 | ) | 2 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2017 | $ | 409 | $ | 141 | $ | 127 | $ | 125 | $ | 140 | $ | 39 | $ | — | $ | 981 | ||||||||||||||||||||||||||||||||||||||||||||||||
2016 | $ | 271 | $ | 37 | $ | 122 | $ | 56 | $ | 166 | $ | (125 | ) | $ | (1 | ) | $ | 526 | 257 | 115 | 124 | 101 | (309 | ) | (164 | ) | (1 | ) | 123 | |||||||||||||||||||||||||||||||||||
2015 | 332 | 149 | 90 | 54 | — | (36 | ) | (2 | ) | 587 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total assets: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
September 30, 2016 | $ | 47,568 | $ | 28,020 | $ | 11,041 | $ | 8,857 | $ | 21,063 | $ | 9,883 | $ | (11,897 | ) | $ | 114,535 | |||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2015 | 46,529 | 26,532 | 10,367 | 8,295 | — | 15,389 | (11,728 | ) | 95,384 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
March 31, 2017 | $ | 48,609 | $ | 28,756 | $ | 10,932 | $ | 8,821 | $ | 21,018 | $ | 10,700 | $ | (11,768 | ) | $ | 117,068 | |||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2016 | 46,974 | 28,335 | 10,831 | 8,704 | 21,025 | 10,369 | (11,334 | ) | 114,904 |
(a) | Generation includes the six |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(b) | Amounts included represent activity for PHI’s successor period, |
(c) | Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities. |
(d) | Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note |
(e) | 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. |
Generation total revenues:Successor and Predecessor PHI:
Three Months Ended September 30, 2016 | Three Months Ended September 30, 2015 | |||||||||||||||||||||||
Revenues from external customers(a) | Intersegment revenues | Total Revenues | Revenues from external customers(a)(c) | Intersegment revenues(c) | Total Revenues(c) | |||||||||||||||||||
Mid-Atlantic | $ | 1,813 | $ | (13 | ) | $ | 1,800 | $ | 1,640 | $ | (8 | ) | $ | 1,632 | ||||||||||
Midwest | 1,163 | 1 | 1,164 | 1,152 | (1 | ) | 1,151 | |||||||||||||||||
New England | 455 | (4 | ) | 451 | 520 | — | 520 | |||||||||||||||||
New York | 331 | (8 | ) | 323 | 254 | (4 | ) | 250 | ||||||||||||||||
ERCOT | 289 | 6 | 295 | 317 | (1 | ) | 316 | |||||||||||||||||
Other Power Regions | 271 | (33 | ) | 238 | 416 | (40 | ) | 376 | ||||||||||||||||
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Total Revenues for Reportable Segments | 4,322 | (51 | ) | 4,271 | 4,299 | (54 | ) | 4,245 | ||||||||||||||||
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Other(b) | 713 | 51 | 764 | 469 | 54 | 523 | ||||||||||||||||||
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Total Generation Consolidated Operating Revenues | $ | 5,035 | $ | — | $ | 5,035 | $ | 4,768 | $ | — | $ | 4,768 | ||||||||||||
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Pepco | DPL | ACE | Other(b) | Intersegment Eliminations | PHI | |||||||||||||||||||
Operating revenues(a): | ||||||||||||||||||||||||
Three Months Ended March 31, 2017 —Successor | ||||||||||||||||||||||||
Rate-regulated electric revenues | $ | 530 | $ | 296 | $ | 275 | $ | — | $ | (4 | ) | $ | 1,097 | |||||||||||
Rate-regulated natural gas revenues | — | 66 | — | — | — | 66 | ||||||||||||||||||
Shared service and other revenues | — | — | — | 12 | — | 12 | ||||||||||||||||||
March 24, 2016 to March 31, 2016 —Successor | ||||||||||||||||||||||||
Rate-regulated electric revenues | $ | 40 | $ | 24 | $ | 23 | $ | 3 | $ | — | $ | 90 | ||||||||||||
Rate-regulated natural gas revenues | — | 3 | — | — | — | 3 | ||||||||||||||||||
Shared service and other revenues | — | — | — | 12 | — | 12 | ||||||||||||||||||
January 1, 2016 to March 23, 2016 —Predecessor | ||||||||||||||||||||||||
Rate-regulated electric revenues | $ | 511 | $ | 279 | $ | 268 | $ | 42 | $ | (4 | ) | $ | 1,096 | |||||||||||
Rate-regulated natural gas revenues | — | 56 | — | 1 | — | 57 | ||||||||||||||||||
Shared service and other revenues | — | — | — | — | — | — | ||||||||||||||||||
Intersegment revenues: | ||||||||||||||||||||||||
Three Months Ended March 31, 2017 —Successor | $ | 1 | $ | 2 | $ | 1 | $ | 13 | $ | (5 | ) | $ | 12 | |||||||||||
March 24, 2016 to March 31, 2016 —Successor | — | — | — | 12 | — | 12 | ||||||||||||||||||
January 1, 2016 to March 23, 2016 —Predecessor | 1 | 2 | 1 | — | (4 | ) | — | |||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||
Three Months Ended March 31, 2017 —Successor | $ | 58 | $ | 57 | $ | 28 | $ | (15 | ) | $ | 12 | $ | 140 | |||||||||||
March 24, 2016 to March 31, 2016 —Successor | (140 | ) | (98 | ) | (105 | ) | 22 | 12 | (309 | ) | ||||||||||||||
January 1, 2016 to March 23, 2016 —Predecessor | 32 | 26 | 5 | (44 | ) | — | 19 | |||||||||||||||||
Total assets: | ||||||||||||||||||||||||
March 31, 2017 — Successor | $ | 7,417 | $ | 4,191 | $ | 3,451 | $ | 10,785 | $ | (4,826 | ) | $ | 21,018 | |||||||||||
December 31, 2016 — Successor | 7,335 | 4,153 | 3,457 | 10,804 | (4,724 | ) | 21,025 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation total revenues net of purchased power and fuel expense:
Three Months Ended September 30, 2016 | Three Months Ended September 30, 2015 | |||||||||||||||||||||||
RNF from external customers(a) | Intersegment RNF | Total RNF | RNF from external customers(a)(c) | Intersegment RNF(c) | Total RNF(c) | |||||||||||||||||||
Mid-Atlantic | $ | 881 | $ | 6 | $ | 887 | $ | 979 | $ | 18 | $ | 997 | ||||||||||||
Midwest | 782 | (1 | ) | 781 | 760 | (4 | ) | 756 | ||||||||||||||||
New England | 170 | (10 | ) | 160 | 148 | (15 | ) | 133 | ||||||||||||||||
New York | 195 | (1 | ) | 194 | 157 | 13 | 170 | |||||||||||||||||
ERCOT | 144 | (51 | ) | 93 | 166 | (55 | ) | 111 | ||||||||||||||||
Other Power Regions | 143 | (66 | ) | 77 | 154 | (71 | ) | 83 | ||||||||||||||||
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Total Revenues net of purchased power and fuel for Reportable Segments | 2,315 | (123 | ) | 2,192 | 2,364 | (114 | ) | 2,250 | ||||||||||||||||
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Other(b) | 131 | 123 | 254 | (115 | ) | 114 | (1 | ) | ||||||||||||||||
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Total Generation Revenues net of purchased power and fuel expense | $ | 2,446 | $ | — | $ | 2,446 | $ | 2,249 | $ | — | $ | 2,249 | ||||||||||||
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Successor and Predecessor PHI:
Pepco | DPL | ACE | Other(b) | Intersegment Eliminations | PHI | |||||||||||||||||||
Operating revenues(a): | ||||||||||||||||||||||||
Three months ended September 30, 2016 — Successor | ||||||||||||||||||||||||
Rate-regulated electric revenues | $ | 635 | $ | 314 | $ | 421 | $ | — | $ | (4 | ) | $ | 1,366 | |||||||||||
Rate-regulated natural gas revenues | — | 17 | — | — | 17 | |||||||||||||||||||
Shared service and other revenues | — | — | — | 11 | — | 11 | ||||||||||||||||||
Three months ended September 30, 2015 — Predecessor | ||||||||||||||||||||||||
Rate-regulated electric revenues | $ | 592 | $ | 295 | $ | 386 | $ | 44 | $ | — | $ | 1,317 | ||||||||||||
Rate-regulated natural gas revenues | — | 19 | — | — | — | 19 | ||||||||||||||||||
Shared service and other revenues | — | — | — | — | — | — | ||||||||||||||||||
Intersegment revenues(e): | ||||||||||||||||||||||||
Three months ended September 30, 2016 — Successor | $ | 1 | $ | 2 | $ | 1 | $ | 11 | $ | (4 | ) | $ | 11 | |||||||||||
Three months ended September 30, 2015 — Predecessor | 1 | 1 | 1 | — | (3 | ) | — | |||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||
Three months ended September 30, 2016 — Successor | $ | 79 | $ | 44 | $ | 47 | $ | (15 | ) | $ | 11 | $ | 166 | |||||||||||
Three months ended September 30, 2015 — Predecessor | 60 | 15 | 22 | (6 | ) | — | 91 | |||||||||||||||||
Total assets: | ||||||||||||||||||||||||
September 30, 2016 — Successor | $ | 7,219 | $ | 4,023 | $ | 3,507 | $ | 11,057 | $ | (4,743 | ) | $ | 21,063 | |||||||||||
December 31, 2015 — Predecessor | 6,908 | 3,969 | 3,387 | 7,162 | (5,238 | ) | 16,188 |
(a) | Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note |
(b) | Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor periods presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Nine Months Ended September 30, 2016 and 2015
Successor | ||||||||||||||||||||||||||||||||
Generation(a) | ComEd | PECO | BGE | PHI(b) | Other(c) | Intersegment Eliminations | Exelon | |||||||||||||||||||||||||
Operating revenues(d): | ||||||||||||||||||||||||||||||||
2016 | ||||||||||||||||||||||||||||||||
Competitive businesses electric revenues | $ | 11,677 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (1,118 | ) | $ | 10,559 | |||||||||||||||
Competitive businesses natural gas revenues | 1,515 | — | — | — | — | — | — | 1,515 | ||||||||||||||||||||||||
Competitive businesses other revenues | 171 | — | — | — | — | — | (2 | ) | 169 | |||||||||||||||||||||||
Rate-regulated electric revenues | — | 4,031 | 1,971 | 1,998 | 2,485 | — | (24 | ) | 10,461 | |||||||||||||||||||||||
Rate-regulated natural gas revenues | — | — | 322 | 423 | 46 | — | (10 | ) | 781 | |||||||||||||||||||||||
Shared service and other revenues | — | — | — | — | 34 | 1,166 | (1,199 | ) | 1 | |||||||||||||||||||||||
2015 | ||||||||||||||||||||||||||||||||
Competitive businesses electric revenues | $ | 12,360 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (564 | ) | $ | 11,796 | |||||||||||||||
Competitive businesses natural gas revenues | 1,901 | — | — | — | — | — | — | 1,901 | ||||||||||||||||||||||||
Competitive businesses other revenues | 580 | — | — | — | — | — | 1 | 581 | ||||||||||||||||||||||||
Rate-regulated electric revenues | — | 3,709 | 1,950 | 1,908 | — | — | (3 | ) | 7,564 | |||||||||||||||||||||||
Rate-regulated natural gas revenues | — | — | 436 | 480 | — | — | (12 | ) | 904 | |||||||||||||||||||||||
Shared service and other revenues | — | — | — | — | — | 1,007 | (1,007 | ) | — | |||||||||||||||||||||||
Intersegment revenues(e): | ||||||||||||||||||||||||||||||||
2016 | $ | 1,121 | $ | 12 | $ | 5 | $ | 16 | $ | 34 | $ | 1,166 | $ | (2,351 | ) | $ | 3 | |||||||||||||||
2015 | 567 | 3 | 1 | 10 | — | 1,003 | (1,581 | ) | 3 | |||||||||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||||||||||
2016 | $ | 556 | $ | 297 | $ | 346 | $ | 191 | $ | (91 | ) | $ | (340 | ) | $ | (3 | ) | $ | 956 | |||||||||||||
2015 | 1,208 | 339 | 299 | 212 | — | (96 | ) | (3 | ) | 1,959 |
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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Generation total revenues:
Nine Months Ended September 30, 2016 | Nine Months Ended September 30, 2015 | Three Months Ended March 31, 2017 | Three Months Ended March 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||
Revenues from external customers(a) | Intersegment revenues | Total Revenues | Revenues from external customers(a)(c) | Intersegment revenues(c) | Total Revenues(c) | Revenues from external customers(a) | Intersegment revenues | Total Revenues | Revenues from external customers(a) | Intersegment revenues | Total Revenues | |||||||||||||||||||||||||||||||||||||
Mid-Atlantic | $ | 4,776 | $ | (40 | ) | $ | 4,736 | $ | 4,560 | $ | (69 | ) | $ | 4,491 | $ | 1,429 | $ | (4 | ) | $ | 1,425 | $ | 1,532 | $ | (12 | ) | $ | 1,520 | ||||||||||||||||||||
Midwest | 3,330 | 13 | 3,343 | 3,634 | (1 | ) | 3,633 | 1,051 | 2 | 1,053 | 1,089 | 6 | 1,095 | |||||||||||||||||||||||||||||||||||
New England | 1,278 | (6 | ) | 1,272 | 1,752 | (6 | ) | 1,746 | 549 | (2 | ) | 547 | 471 | (1 | ) | 470 | ||||||||||||||||||||||||||||||||
New York | 906 | (33 | ) | 873 | 783 | (5 | ) | 778 | 310 | (3 | ) | 307 | 218 | (15 | ) | 203 | ||||||||||||||||||||||||||||||||
ERCOT | 659 | 6 | 665 | 691 | (4 | ) | 687 | 192 | (1 | ) | 191 | 163 | — | 163 | ||||||||||||||||||||||||||||||||||
Other Power Regions | 728 | (42 | ) | 686 | 940 | (60 | ) | 880 | 189 | (5 | ) | 184 | 222 | 1 | 223 | |||||||||||||||||||||||||||||||||
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Total Revenues for Reportable Segments | 11,677 | (102 | ) | 11,575 | 12,360 | (145 | ) | 12,215 | 3,720 | (13 | ) | 3,707 | 3,695 | (21 | ) | 3,674 | ||||||||||||||||||||||||||||||||
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Other(b) | 1,686 | 102 | 1,788 | 2,481 | 145 | 2,626 | 1,168 | 13 | 1,181 | 1,044 | 21 | 1,065 | ||||||||||||||||||||||||||||||||||||
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Total Generation Consolidated Operating Revenues | $ | 13,363 | $ | — | $ | 13,363 | $ | 14,841 | $ | — | $ | 14,841 | $ | 4,888 | $ | — | $ | 4,888 | $ | 4,739 | $ | — | $ | 4,739 | ||||||||||||||||||||||||
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__________
(a) | Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants. |
(b) | Other represents activities not allocated to a region. See text above for a description of included activities. Includes a |
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation total revenues net of purchased power and fuel expense:
Nine Months Ended September 30, 2016 | Nine Months Ended September 30, 2015 | Three Months Ended March 31, 2017 | Three Months Ended March 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||
RNF from external customers(a) | Intersegment RNF | Total RNF | RNF from external customers(a)(c) | Intersegment RNF(c) | Total RNF(c) | RNF from external customers(a) | Intersegment RNF | Total RNF | RNF from external customers(a) | Intersegment RN | Total RNF | |||||||||||||||||||||||||||||||||||||
Mid-Atlantic | $ | 2,541 | $ | 15 | $ | 2,556 | $ | 2,679 | $ | (2 | ) | $ | 2,677 | $ | 755 | $ | 18 | $ | 773 | $ | 832 | $ | 9 | $ | 841 | |||||||||||||||||||||||
Midwest | 2,225 | 4 | 2,229 | 2,220 | (15 | ) | 2,205 | 704 | 11 | 715 | 715 | 3 | 718 | |||||||||||||||||||||||||||||||||||
New England | 373 | (23 | ) | 350 | 425 | (46 | ) | 379 | 115 | (4 | ) | 111 | 86 | (5 | ) | 81 | ||||||||||||||||||||||||||||||||
New York | 607 | (15 | ) | 592 | 462 | 40 | 502 | 153 | — | 153 | 141 | (11 | ) | 130 | ||||||||||||||||||||||||||||||||||
ERCOT | 335 | (104 | ) | 231 | 344 | (109 | ) | 235 | 94 | (25 | ) | 69 | 81 | (20 | ) | 61 | ||||||||||||||||||||||||||||||||
Other Power Regions | 357 | (104 | ) | 253 | 341 | (148 | ) | 193 | 108 | (44 | ) | 64 | 86 | (10 | ) | 76 | ||||||||||||||||||||||||||||||||
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Total Revenues net of purchased power and fuel expense for Reportable Segments | 6,438 | (227 | ) | 6,211 | 6,471 | (280 | ) | 6,191 | 1,929 | (44 | ) | 1,885 | 1,941 | (34 | ) | 1,907 | ||||||||||||||||||||||||||||||||
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Other(b) | 316 | 227 | 543 | 570 | 280 | 850 | 161 | 44 | 205 | 356 | 34 | 390 | ||||||||||||||||||||||||||||||||||||
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Total Generation Revenues net of purchased power and fuel expense | $ | 6,754 | $ | — | $ | 6,754 | $ | 7,041 | $ | — | $ | 7,041 | $ | 2,090 | $ | — | $ | 2,090 | $ | 2,297 | $ | — | $ | 2,297 | ||||||||||||||||||||||||
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(a) | Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants. |
(b) | Other represents activities not allocated to a region. See text above for a description of included activities. Includes a |
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)20. Subsequent Events (Exelon and Generation)
(DollarsEGTP, a Delaware limited liability company, was formed in millions, except per share data, unless otherwise noted)2014 with the purpose of financing a portfolio of assets comprised of two combined-cycle gas turbines (CCGTs) and three peaking/simple cycle facilities consisting of approximately 3.4 GW of generation capacity in ERCOT North and Houston Zones. EGTP is an indirect wholly owned subsidiary of Exelon and Generation. Each of the aforementioned facilities is held through a wholly-owned direct subsidiary of EGTP. EGTP also owns two equity method investments in shared facility companies. EGTP, its direct parent and its wholly owned subsidiaries secure a nonrecourse senior secured term loan facility, a revolving loan facility and certain commodity and interest rate swaps.
SuccessorEGTP’s operating cash flows have been negatively impacted by certain market conditions including, but not limited to: low power prices, higher fuel prices and Predecessor PHI:the seasonality of its cash flows. Despite the declining operating cash flows, EGTP remained in compliance with its covenants related to the project financing through March 31, 2017. On May 2, 2017, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly-owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of administering the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP, including the revolving credit facility. As a result, in the second quarter, Exelon and Generation will reclassify certain EGTP’s assets and liabilities on Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. Exelon and Generation estimate a pre-tax impairment charge upon reclassification ranging from $300 million to $400 million will be recognized in the second quarter of 2017. See Note 10 — Debt and Credit Agreements for details regarding the nonrecourse debt associated with EGTP. The resolution of this matter has no direct effect on any other Exelon or Generation debt or credit facilities.
Pepco | DPL | ACE | Other(b) | Intersegment Eliminations | PHI | |||||||||||||||||||
Operating revenues(a): | ||||||||||||||||||||||||
March 24, 2016 to September 30, 2016 — Successor | ||||||||||||||||||||||||
Rate-regulated electric revenues | $ | 1,184 | $ | 593 | $ | 714 | $ | 3 | $ | (9 | ) | $ | 2,485 | |||||||||||
Rate-regulated natural gas revenues | — | 46 | — | — | — | 46 | ||||||||||||||||||
Shared service and other revenues | — | — | — | 34 | — | 34 | ||||||||||||||||||
January 1, 2016 to March 23, 2016 — Predecessor | ||||||||||||||||||||||||
Rate-regulated electric revenues | $ | 511 | $ | 279 | $ | 268 | $ | 42 | $ | (4 | ) | $ | 1,096 | |||||||||||
Rate-regulated natural gas revenues | — | 56 | — | 1 | — | 57 | ||||||||||||||||||
Shared service and other revenues | — | — | — | — | — | — | ||||||||||||||||||
Nine months ended September 30, 2015 — Predecessor | ||||||||||||||||||||||||
Rate-regulated electric revenues | $ | 1,641 | $ | 875 | $ | 1,003 | $ | 161 | $ | — | $ | 3,680 | ||||||||||||
Rate-regulated natural gas revenues | — | 129 | — | — | — | 129 | ||||||||||||||||||
Shared service and other revenues | — | — | — | — | — | — | ||||||||||||||||||
Intersegment revenues: | ||||||||||||||||||||||||
March 24, 2016 to September 30, 2016 — Successor | $ | 2 | $ | 4 | $ | 2 | $ | 35 | $ | (9 | ) | $ | 34 | |||||||||||
January 1, 2016 to March 23, 2016 — Predecessor | 1 | 2 | 1 | — | (4 | ) | — | |||||||||||||||||
Nine months ended September 30, 2015 — Predecessor | 4 | 4 | 2 | — | (10 | ) | — | |||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||
March 24, 2016 to September 30, 2016 — Successor | $ | (12 | ) | $ | (42 | ) | $ | (55 | ) | $ | (16 | ) | $ | 34 | $ | (91 | ) | |||||||
January 1, 2016 to March 23, 2016 — Predecessor | 32 | 26 | 5 | (44 | ) | — | 19 | |||||||||||||||||
Nine months ended September 30, 2015 — Predecessor | 128 | 55 | 37 | (23 | ) | — | 197 |
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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, a utility services holding company, operates through the following principal subsidiaries:
• | Generation,whose integrated business consists of the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services. |
• | ComEd, |
• | PECO,whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in the Pennsylvania counties surrounding the City of Philadelphia. |
• | BGE,whose business consists of the purchase and regulated retail sale of electricity and natural gas and the provision of electricity distribution and transmission and natural gas distribution services in central Maryland, including the City of Baltimore. |
• | Pepco,whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. |
• | DPL,whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware. |
• | ACE,whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in southern New Jersey. |
Pepco, DPL and ACE are operating companies of PHI, which is a utility services holding company and a wholly owned subsidiary of Exelon.
Exelon has twelve reportable segments consisting of Generation’s six power marketing reportable segments (Mid-Atlantic,(Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions in Generation), ComEd, PECO, BGE and PHI’s three utility reportable segments (Pepco, DPL and ACE). See Note 20—19 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon’s reportable segments.
Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of support services at cost. The costs of these services are directly charged or allocated to the applicable operating segments. Additionally, the results of Exelon’s corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities.
PHI Service Company, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, accounting, engineering, distribution and transmission planning, asset management, system operations, and power procurement, to PHI and its operating subsidiaries. These services are directly charged or allocated pursuant to service agreements among PHI Service Company and the participating operating subsidiaries.
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.
Executive OverviewFinancial Results of Operations
FinancialGAAP Results of Operations
The following tables settable sets forth theExelon’s GAAP consolidated financial results of Exelonoperations for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015.2016. The 2016 financial results onlyamounts include the operations of PHI, Pepco, DPL and ACE from March 24, 2016 through September 30,March 31, 2016. All amounts presented below are before the impact of income taxes, except as noted.
Three Months Ended September 30, | Favorable (Unfavorable) Variance | Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Generation | ComEd | PECO | BGE | PHI(b) | Other | Exelon | Exelon | Generation | ComEd | PECO | BGE | PHI | Other | Exelon | Exelon(b) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 5,035 | $ | 1,497 | $ | 788 | $ | 812 | $ | 1,394 | $ | (524 | ) | $ | 9,002 | $ | 7,401 | $ | 1,601 | $ | 4,888 | $ | 1,298 | $ | 796 | $ | 951 | $ | 1,175 | $ | (351 | ) | $ | 8,757 | $ | 7,573 | $ | 1,184 | ||||||||||||||||||||||||||||||||||
Purchased power and fuel | 2,589 | 454 | 272 | 360 | 583 | (504 | ) | 3,754 | 3,291 | (463 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased power and fuel expense | 2,798 | 334 | 287 | 350 | 461 | (331 | ) | 3,899 | 3,254 | (645 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Revenue net of purchased power and fuel(a) | 2,446 | 1,043 | 516 | 452 | 811 | (20 | ) | 5,248 | 4,110 | 1,138 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue net of purchased power and fuel expense(a) | 2,090 | 964 | 509 | 601 | 714 | (20 | ) | 4,858 | 4,319 | 539 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Other operating expenses | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating and maintenance | 1,336 | 377 | 199 | 178 | 226 | 22 | 2,338 | 1,996 | (342 | ) | 1,488 | 370 | 208 | 183 | 256 | (45 | ) | 2,460 | 2,835 | 375 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Depreciation and amortization | 632 | 196 | 67 | 101 | 182 | 17 | 1,195 | 606 | (589 | ) | 302 | 208 | 71 | 128 | 167 | 20 | 896 | 685 | (211 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Taxes other than income | 136 | 82 | 46 | 58 | 124 | 3 | 449 | 310 | (139 | ) | 143 | 72 | 38 | 62 | 111 | 10 | 436 | 325 | (111 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
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Total other operating expenses | 2,104 | 655 | 312 | 337 | 532 | 42 | 3,982 | 2,912 | (1,070 | ) | 1,933 | 650 | 317 | 373 | 534 | (15 | ) | 3,792 | 3,845 | 53 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Gain on sales of assets | — | 1 | — | — | — | — | 1 | 2 | (1 | ) | 4 | — | — | — | — | — | 4 | 9 | (5 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Bargain purchase gain | 226 | — | — | — | — | — | 226 | — | 226 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Operating income (loss) | 342 | 389 | 204 | 115 | 279 | (62 | ) | 1,267 | 1,200 | 67 | 387 | 314 | 192 | 228 | 180 | (5 | ) | 1,296 | 483 | 813 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
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Other income and (deductions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest expense, net | (77 | ) | (197 | ) | (30 | ) | (28 | ) | (64 | ) | (120 | ) | (516 | ) | (253 | ) | (263 | ) | (100 | ) | (85 | ) | (31 | ) | (27 | ) | (62 | ) | (68 | ) | (373 | ) | (287 | ) | (86 | ) | ||||||||||||||||||||||||||||||||||||
Other, net | 185 | (80 | ) | 2 | 5 | 19 | (11 | ) | 120 | (244 | ) | 364 | 259 | 4 | 2 | 4 | 13 | 1 | 283 | 114 | 169 | |||||||||||||||||||||||||||||||||||||||||||||||||||
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Total other income and (deductions) | 108 | (277 | ) | (28 | ) | (23 | ) | (45 | ) | (131 | ) | (396 | ) | (497 | ) | 101 | 159 | (81 | ) | (29 | ) | (23 | ) | (49 | ) | (67 | ) | (90 | ) | (173 | ) | 83 | ||||||||||||||||||||||||||||||||||||||||
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Income (loss) before income taxes | 450 | 112 | 176 | 92 | 234 | (193 | ) | 871 | 703 | 168 | 546 | 233 | 163 | 205 | 131 | (72 | ) | 1,206 | 310 | 896 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Income taxes | 173 | 75 | 54 | 36 | 68 | (66 | ) | 340 | 115 | (225 | ) | 127 | 92 | 36 | 80 | (9 | ) | (111 | ) | 215 | 184 | (31 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||
Equity in (losses) earnings of unconsolidated affiliates | (6 | ) | — | — | — | — | 1 | (5 | ) | (1 | ) | (4 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity in losses of unconsolidated affiliates | (10 | ) | — | — | — | — | — | (10 | ) | (3 | ) | (7 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Net income (loss) | 271 | 37 | 122 | 56 | 166 | (126 | ) | 526 | 587 | (61 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net income (loss) attributable to noncontrolling interests and preference stock dividends | 35 | — | — | 2 | — | (1 | ) | 36 | (42 | ) | (78 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net income | 409 | 141 | 127 | 125 | 140 | 39 | 981 | 123 | 858 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net loss attributable to noncontrolling interests and preference stock dividends | (14 | ) | — | — | — | — | — | (14 | ) | (50 | ) | (36 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Net income (loss) attributable to common shareholders | $ | 236 | $ | 37 | $ | 122 | $ | 54 | $ | 166 | $ | (125 | ) | $ | 490 | $ | 629 | $ | (139 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Net income attributable to common shareholders | $ | 423 | $ | 141 | $ | 127 | $ | 125 | $ | 140 | $ | 39 | $ | 995 | $ | 173 | $ | 822 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
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(a) | The Registrants evaluate operating performance using the measure of |
provides information that can be used to evaluate their operational performance. |
(b) | As a result of the PHI Merger, |
Operating revenues Purchased power and fuel Revenue net of purchased power and fuel(a) Other operating expenses Operating and maintenance Depreciation and amortization Taxes other than income Total other operating expenses Gain on sales of assets Operating income (loss) Other income and (deductions) Interest expense, net Other, net Total other income and (deductions) Income (loss) before income taxes Income taxes Equity in losses of unconsolidated affiliates Net income (loss) Net income attributable to noncontrolling interests and preference stock dividends Net income (loss) attributable to common shareholders Nine Months Ended September 30, Favorable
(Unfavorable)
Variance 2016 2015 Generation ComEd PECO BGE PHI(b) Other Exelon Exelon $ 13,363 $ 4,031 $ 2,293 $ 2,421 $ 2,565 $ (1,187 ) $ 23,486 $ 22,746 $ 740 6,609 1,141 809 994 1,037 (1,128 ) 9,462 10,210 748 6,754 2,890 1,484 1,427 1,528 (59 ) 14,024 12,536 1,488 4,333 1,113 604 588 921 118 7,677 6,119 (1,558 ) 1,329 574 201 307 355 55 2,821 1,818 (1,003 ) 380 222 126 172 248 20 1,168 908 (260 ) 6,042 1,909 931 1,067 1,524 193 11,666 8,845 (2,821 ) 31 6 — — — 4 41 10 31 743 987 553 360 4 (248 ) 2,399 3,701 (1,302 ) (273 ) (374 ) (92 ) (76 ) (135 ) (229 ) (1,179 ) (755 ) (424 ) 395 (72 ) 6 16 31 1 377 (179 ) 556 122 (446 ) (86 ) (60 ) (104 ) (228 ) (802 ) (934 ) 132 865 541 467 300 (100 ) (476 ) 1,597 2,767 (1,170 ) 293 244 121 109 (9 ) (133 ) 625 805 180 (16 ) — — — — — (16 ) (3 ) (13 ) 556 297 346 191 (91 ) (343 ) 956 1,959 (1,003 ) 18 — — 8 — — 26 — (26 ) $ 538 $ 297 $ 346 $ 183 $ (91 ) $ (343 ) $ 930 $ 1,959 $ (1,029 )
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Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.March 31, 2016.Exelon’s net income attributable to common shareholders was $490$995 million for the three months ended September 30, 2016March 31, 2017 as compared to $629$173 million for the three months ended September 30, 2015,March 31, 2016, and diluted earnings per average common share were $0.53$1.07 for the three months ended September 30, 2016March 31, 2017 as compared to $0.69$0.19 for the three months ended September 30, 2015.March 31, 2016.
Operating revenueRevenue net of purchased power and fuel expense, which is anon-GAAP measure discussed below, increased by $1.1 billion$539 million for the three months ended September 30, 2016March 31, 2017 as compared to the same period in 2015.2016. The quarter-over-quarteryear-over-year increase in operating revenue net of purchased power and fuel expense was primarily due to the following favorable factors:
Increase of $227 million at Generation due to mark-to-market gains of $88 million in 2016 from economic hedging activities as compared to losses of $139 million in 2015;
Increase of $57$63 million at ComEd primarily due to increased distribution and transmission formula rate revenue resulting from favorable weather anddecoupling impacts, increased capital investment, partially offset by lowerincreased depreciation expense and higher allowed electric distribution ROE due to a decreasean increase in treasury rates, as well as, favorable weather;rates;
Increase of $54 million at PECO primarily due to increased electric distribution revenue pursuant to a rate increase effective January 1, 2016, as well as favorable summer weather;
Increase of $38$45 million at BGE primarily due to increased transmissiondistribution revenue as a result of increased capital investmentselectric and operating and maintenance expense recoveries and increased distribution revenue pursuant to a rate increasenatural gas rates increases effective in June 2016; and
Increase of $811$647 million in revenue net of purchased power and fuel due to the inclusion of PHI’s results for the three months ended March 31, 2017 compared to the period of July 1,March 24, 2016 to September 30,March 31, 2016.
The quarter-over-quarteryear-over-year increase in operating revenue net of purchased power and fuel expense was partially offset by a decreasethe following factors:
Decrease of $58$152 million at Generation due tomark-to-market losses of $49 million in 2017 from economic hedging activities as compared to gains of $103 million in 2016; and
Decrease of $55 million at Generation primarily due to the impacts of declining natural gas prices on Generation’s natural gas portfolio, decreased capacity prices and lower realized energy prices, partially offset by the impact of the Ginna Reliability Support Services Agreement and the absence of oil inventory write downs in the Mid-Atlantic region.2017.
Operating and maintenance expense increaseddecreased by $342$375 million for the three months ended September 30, 2016March 31, 2017 as compared to the same period in 20152016 primarily due to the following favorable factors:
Decrease of $141 million at Corporate due to merger commitments of $1 million in 2017 compared to $142 million in 2016;
Decrease of $109 million at Generation due to long-lived asset impairments of $10 million in 2017 compared to $119 million in 2016;
Decrease of $34 million at Corporate due to the absence of certain merger and integration costs in 2017 compared to $34 million in 2016;
Decrease of $12 million at BGE due to lower incremental storm costs in the first quarter of 2017 compared to the first quarter of 2016; and
Decrease of $425 million at PHI primarily due to the deferral of previously expensed merger-related costs of $6 million for the three months ended March 31, 2017 compared to merger commitment and other merger-related costs of $419 million for the period March 24, 2016 to March 31, 2016.
The year-over-year decrease in operating and maintenance expense was partially offset by the following unfavorable factors:
Increase in Generation’s labor, contracting and materials cost of $106$95 million relatedprimarily due to increased merger and integration costs, the inclusion of Pepco Energy Services results in 2016;
Increase of $7 million at BGE primarily duefor the three months ended March 31, 2017 compared to the period March 24, 2016 to March 31, 2016 and increased conduit rental fees assessed by the City of Baltimore;contracting costs related to energy efficiency projects; and
Increase of $226$28 million at Generation due to increased nuclear outage costs; and
Increase of $232 million, exclusive of merger-related costs discussed above, in operating and maintenance expense due to the inclusion of PHI’s results for the three months ended March 31, 2017 compared to the period of July 1,March 24, 2016 to September 30,March 31, 2016.
The quarter-over-quarter increase in operating and maintenance expense was partially offset by a decrease of $20 million in pension and non-pension post-retirement benefits resulting from the favorable impact of higher pension and OPEB discount rates in 2016.
Depreciation and amortization expense increased by $589$211 million primarily due to increased depreciation expense as a result of accelerated depreciation and amortization expense related to Generation’s 2016 decision to early retire the Clinton and Quad Cities nuclear generating facilities, increased nuclear decommissioning amortization at Generation, increased depreciation expense due to ongoing capital expenditures across all operating companies and the inclusion of PHI’s results for the three months ended March 31, 2017 compared to the period of July 1,March 24, 2016 to September 30,March 31, 2016.
Taxes other than income increased by $139$111 million primarily due to increased property and utility taxes as a result of the inclusion of PHI’s results for the three months ended March 31, 2017 compared to the period of July 1,March 24, 2016 to September 30,March 31, 2016.
Bargain purchase gain increased by $226 million due to the gain associated with the FitzPatrick acquisition.
Interest expense, net increased by $263$86 million primarily due to the recognition of the interest due on the asserted penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position,higher outstanding debt and the inclusion of PHI’s results for the three months ended March 31, 2017 compared to the period of July 1,March 24, 2016 to September 30, 2016 and higher outstanding debt to fund the PHI acquisition and general corporate purposes.March 31, 2016.
Other, net increased by $364$169 million primarily due to the recognition of the penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position and the change in realized and unrealized gains and losses on NDT funds at Generation.
Exelon’s effective income tax rates for the three months ended September 30,March 31, 2017 and 2016 were 17.8% and 2015 were 39.0% and 16.4%59.4%, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015.Exelon’s net income attributable to common shareholders was $930 million for the nine months ended September 30, 2016 as compared to $1,959 million for the nine months ended September 30, 2015, and diluted earnings per average common share were $1.00 for the nine months ended September 30, 2016 as compared to $2.22 for the nine months ended September 30, 2015.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $1.5 billion for the nine months ended September 30, 2016 as compared to the same period in 2015. The year-over-year increase in operating revenue net of purchased power and fuel expense was primarily due to the following favorable factors:
Increase of $172 million at ComEd primarily due to increased distribution and transmission formula rate revenue resulting from increased capital investment, as well as, favorable weather;
Increase of $76 million at BGE primarily due to increased transmission revenue as a result of increased capital investments and operating and maintenance expense recoveries and increased distribution revenue pursuant to a rate increase effective in June 2016;
Increase of $51 million at PECO primarily due to increased electric distribution revenue pursuant to a rate increase effective January 1, 2016;
Increase of $20 million at Generation primarily due to approval of the Ginna Reliability Support Services Agreement, decreased nuclear fuel prices and decreased nuclear outage days at higher capacity units, partially offset by lower realized energy prices, and higher oil inventory write downs; and
Increase of $1,528 million in revenue net of purchased power and fuel due to the inclusion of PHI’s results for the period of March 24, 2016 to September 30, 2016.
The year-over-year increase in operating revenue net of purchased power and fuel expense was partially offset by a decrease of $371 million at Generation due to mark-to-market losses of $113 million in 2016 from economic hedging activities as compared to gains of $258 million in 2015.
Operating and maintenance expense increased by $1.6 billion for the nine months ended September 30, 2016 as compared to the same period in 2015 primarily due to the following unfavorable factors:
Approval of the merger across all regulatory jurisdictions was conditioned on Exelon and PHI agreeing to certain commitments pursuant to which, upon acquisition close, Exelon recorded $513 million of costs;
Long-lived asset impairments of Upstream assets and certain wind projects at Generation of $171 million;
Increase of $146 million at Generation for the recognition of one-time charges associated with Generation’s 2016 decision to early retire the Clinton and Quad Cities nuclear generating facilities;
Increase in Generation’s labor, contracting and materials cost of $144 million related to the inclusion of Pepco Energy Services results in 2016;
Increase of $52 million at BGE as a result of one-time charges associated with the reduction of certain regulatory assets and other long-lived assets stemming from certain cost disallowances contained within the smart grid rate case orders issued by the MDPSC in June and July 2016;
Increase of $22 million at BGE due to increased conduit rental fees assessed by the City of Baltimore;
Increased storm costs at BGE of $19 million; and
Increase of $607 million, exclusive of merger commitment costs discussed above, due to the inclusion of PHI’s results for the period March 24, 2016 to September 30, 2016.
The year-over-year increase in operating and maintenance expense was partially offset by the following favorable factors:
Decrease of $60 million in pension and non-pension post-retirement benefits resulting from the favorable impact of higher pension and OPEB discount rates in 2016;
Decrease of $31 million in the provision for uncollectible accounts at ComEd, PECO and BGE; and
Decrease of $9 million at PECO due to lower incremental storm costs in the second quarter of 2016 compared to the second quarter of 2015, as a result of the June 2015 storm.
Depreciation and amortization expense increased by $1,003 million primarily as a result of accelerated depreciation and amortization expense related to Generation’s 2016 decision to early retire the Clinton and Quad Cities nuclear generating facilities, increased nuclear decommissioning amortization at Generation, increased depreciation expense due to ongoing capital expenditures across all operating companies, and the inclusion of PHI’s results for the period of March 24, 2016 to September 30, 2016.
Taxes other than income increased by $260 million primarily due to increased property and utility taxes as a result of the inclusion of PHI’s results for the period March 24, 2016 to September 30, 2016.
Gain on sales of assets increased by $31 million primarily as a result of the gain associated with Generation’s sale of the retired New Boston generating site.
Interest expense, net increased by $424 million primarily due to the recognition of the interest due on the asserted penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position, higher outstanding debt to fund the PHI acquisition and general corporate purposes and the absence of the forward-starting interest rate swaps in 2016.
Other, net increased by $556 million primarily due to the recognition of the penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position, the change in realized and unrealized gains and losses on NDT funds at Generation and the absence of a $26 million loss in 2015 on the termination of forward-starting interest rate swaps.
Exelon’s effective income tax rates for the nine months ended September 30, 2016 and 2015 were 39.1% and 29.1%, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. As a result of the merger, Exelon recorded an after-tax charge of $91 million during the nine months ended September 30, 2016 as a result of the assessment and remeasurement of certain federal and state PHI, Pepco, DPL and ACE uncertain tax positions.
For further detail regarding the financial results for the three and nine months ended September 30, 2016,March 31, 2017, including explanation of thenon-GAAP measure revenue net of purchased power and fuel expense, see the discussions of Results of Operations by Segment below.
Non-GAAP Financial MeasuresAdjusted(non-GAAP) Operating Earnings
Exelon’s adjusted(non-GAAP) operating earnings for the three months ended September 30, 2016March 31, 2017 were $841$605 million, or $0.91$0.65 per diluted share, compared with adjusted(non-GAAP) operating earnings of $757$632 million, or $0.83$0.68 per diluted share for the same period in 2015. Exelon’s adjusted (non-GAAP) operating
earnings for the nine months ended September 30, 2016 were $2,078 million, or $2.24 per diluted share, compared with adjusted (non-GAAP) operating earnings of $1,880 million, or $2.13 per diluted share for the same period in 2015.2016. In addition to net income, as determined under generally accepted accounting principles in the United States (GAAP), 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 period over periodperiod-over-period 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. The Company has provided non-GAAP financial measures as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. Non-GAAP financial measures should not bepresentations or deemed more useful than a substitute for, or an alternative to the most comparable GAAP measuresinformation provided elsewhere in this report.
The following table provides a reconciliation between net income attributable to common shareholders as determined in accordance with GAAP and adjusted(non-GAAP) operating earnings for the three and nine months ended September 30, 2016March 31, 2017 as compared to the same periodsperiod in 2015.2016. The footnotes below the table provide tax expense (benefit) impacts:
Three Months Ended September 30, | ||||||||||||||||
2016 | 2015 | |||||||||||||||
(All amounts after tax) | Earnings per Diluted Share | Earnings per Diluted Share | ||||||||||||||
Net Income Attributable to Common Shareholders | $ | 490 | $ | 0.53 | $ | 629 | $ | 0.69 | ||||||||
Mark-to-Market Impact of Economic Hedging Activities(a) | (54 | ) | (0.06 | ) | 85 | 0.09 | ||||||||||
Unrealized (Gains) Losses Related to NDT Fund Investments(b) | (70 | ) | (0.07 | ) | 133 | 0.15 | ||||||||||
Merger and Integration Costs(c) | 13 | 0.01 | 12 | 0.02 | ||||||||||||
Merger Commitments(d) | 5 | 0.01 | — | — | ||||||||||||
Long-Lived Asset Impairments(e) | 11 | 0.01 | — | — | ||||||||||||
Amortization of Commodity Contract Intangibles(f) | 13 | 0.01 | 2 | — | ||||||||||||
Plant Retirements and Divestitures(g) | 204 | 0.22 | — | — | ||||||||||||
Cost Management Program(h) | 7 | 0.01 | — | — | ||||||||||||
Like-Kind Exchange Tax Position(i) | 199 | 0.21 | — | — | ||||||||||||
Asset Retirement Obligation(j) | — | — | (6 | ) | (0.01 | ) | ||||||||||
Tax Settlements(k) | — | — | (52 | ) | (0.06 | ) | ||||||||||
CENG Non-Controlling Interests(n) | 23 | 0.03 | (46 | ) | (0.05 | ) | ||||||||||
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Adjusted (non-GAAP) Operating Earnings | $ | 841 | $ | 0.91 | $ | 757 | $ | 0.83 | ||||||||
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(All amounts after tax) Net Income Attributable to Common Shareholders Mark-to-Market Impact of Economic Hedging Activities(a) Unrealized (Gains) Losses Related to NDT Fund Investments(b) Merger and Integration Costs(c) Merger Commitments(d) Long-Lived Asset Impairments(e) Amortization of Commodity Contract Intangibles(f) Plant Retirements and Divestitures(g) Cost Management Program(h) Like-Kind Exchange Tax Position(i) Asset Retirement Obligation(j) Tax Settlements(k) Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps(l) Midwest Generation Bankruptcy Recoveries(m) CENG Non-Controlling Interests(n) Adjusted (non-GAAP) Operating Earnings (All amounts after tax) Net Income Attributable to Common Shareholders Mark-to-Market Impact of Economic Hedging Activities(a) Unrealized (Gains) Related to NDT Fund Investments(b) Merger and Integration Costs(c) Merger Commitments(d) Long-Lived Asset Impairments(e) Amortization of Commodity Contract Intangibles(f) Cost Management Program(g) Tax Settlements(h) Reassessment of State Deferred Income Taxes(i) Bargain Purchase Gain(j) CENG Noncontrolling Interests(k) Adjusted(non-GAAP) Operating Earnings Nine Months Ended September 30, 2016 2015 Earnings per
Diluted Share Earnings per
Diluted Share $ 930 $ 1.00 $ 1,959 $ 2.22 67 0.07 (158 ) (0.18 ) (127 ) (0.13 ) 164 0.19 92 0.10 50 0.06 400 0.43 — — 104 0.11 15 0.02 8 0.01 (13 ) (0.01 ) 338 0.37 — — 26 0.03 — — 199 0.21 — — — — (6 ) (0.01 ) — — (52 ) (0.06 ) — — (21 ) (0.03 ) — — (6 ) (0.01 ) 41 0.04 (52 ) (0.06 ) $ 2,078 $ 2.24 $ 1,880 $ 2.13 Three Months Ended March 31, 2017 2016 Earnings per
Diluted Share Earnings per
Diluted Share $ 995 $ 1.07 $ 173 $ 0.19 30 0.03 (64 ) (0.07 ) (99 ) (0.10 ) (31 ) (0.03 ) 25 0.03 76 0.08 (137 ) (0.15 ) 394 0.42 — — 71 0.07 3 — (12 ) (0.01 ) 4 — 14 0.02 (5 ) (0.01 ) — — (20 ) (0.02 ) — — (226 ) (0.24 ) — — 35 0.04 11 0.01 $ 605 $ 0.65 $ 632 $ 0.68
(a) | Reflects the impact of net losses (gains) |
(b) | Reflects the impact of net unrealized (gains) losses for the three months ended |
(c) | Reflects certain costs incurred for the PHI acquisition for the three months ended |
(d) |
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(e) | Reflects the impairment of Upstream assets |
(f) | Reflects thenon-cash impact for the three months ended |
(g) | Reflects |
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Represents Generation’s noncontrolling |
Merger and Acquisition Costs
On March 23, 2016, the Exelon and PHI Merger was completed. On the merger date, PHI shareholders received $27.25 of cash in exchange for each share of PHI common stock. The resulting company retained the Exelon name and is headquartered in Chicago.
As a result of the PHI Merger, Exelon has incurred costs associated with evaluating, structuring and executing the PHI Merger transaction itself, and will continue to incur cost associated with meeting the various commitments set forth by regulators and agreed-upon with other interested parties as part of the merger approval process, and integrating the former PHI businesses into Exelon.
The table below presents the one-time pre-tax charges recognized for the PHI Merger included in the Registrant’s respective Consolidated Statements of Operations and Comprehensive Income.
Successor | ||||||||||||||||||||||||
Nine Months Ended September 30, 2016 | March 24, 2016 to September 30, 2016 | |||||||||||||||||||||||
Exelon | Generation | Pepco | DPL | ACE | PHI | |||||||||||||||||||
Merger commitments | $ | 513 | $ | 3 | $ | 126 | $ | 77 | $ | 111 | $ | 314 | ||||||||||||
Changes in accounting and tax related policies and estimates | — | — | 25 | 15 | 5 | — | ||||||||||||||||||
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Total | $ | 513 | $ | 3 | $ | 151 | $ | 92 | $ | 116 | $ | 314 | ||||||||||||
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In addition to the one-time PHI Merger charges discussed above, forFor the three and nine months ended September 30,March 31, 2017 and 2016, and 2015, expense has been recognized for the PHI Merger Constellation acquisition and FitzPatrick acquisition as follows:
Merger, Integration and Acquisition Costs: | Pre-tax Expense | |||||||||||||||||||||||||||||||||||
Three Months Ended September 30, 2016 | ||||||||||||||||||||||||||||||||||||
Exelon(a) | Generation(a) | ComEd | PECO | BGE | PHI(a) | Pepco(a) | DPL(a) | ACE(a) | ||||||||||||||||||||||||||||
Transaction(c) | $ | 1 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||
Employee-Related(d) | 1 | — | — | — | — | 1 | — | — | — | |||||||||||||||||||||||||||
Other | 21 | 11 | — | 2 | 2 | 7 | 3 | 2 | 2 | |||||||||||||||||||||||||||
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Total | $ | 23 | $ | 11 | $ | — | $ | 2 | $ | 2 | $ | 8 | $ | 3 | $ | 2 | $ | 2 | ||||||||||||||||||
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Pre-tax Expense | Pre-tax Expense | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, 2015 | Three Months Ended March 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Merger, Integration and Acquisition Costs: | Exelon | Generation | ComEd | PECO | BGE | Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE | ||||||||||||||||||||||||||||||||||||||||||
Transaction | $ | 5 | $ | — | $ | — | $ | — | $ | — | $ | 1 | $ | 1 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||
Other | 17 | 10 | 3 | 1 | 2 | 40 | 41 | — | 1 | 2 | (5 | ) | 1 | (7 | ) | 1 | ||||||||||||||||||||||||||||||||||||||||
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Total | $ | 22 | $ | 10 | $ | 3 | $ | 1 | $ | 2 | $ | 41 | $ | 42 | $ | — | $ | 1 | $ | 2 | $ | (5 | ) | $ | 1 | $ | (7 | ) | $ | 1 | ||||||||||||||||||||||||||
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Merger, Integration and Acquisition Costs: | Pre-tax Expense | |||||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2016 | ||||||||||||||||||||||||||||||||||||
Exelon(a) | Generation(a) | ComEd | PECO | BGE | PHI(a) | Pepco(a) | DPL(a) | ACE(a) | ||||||||||||||||||||||||||||
Transaction(c) | $ | 36 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||
Employee-Related(d) | 74 | 10 | 1 | 1 | 1 | 61 | 29 | 17 | 14 | |||||||||||||||||||||||||||
Other(e) | 16 | 21 | (8 | ) | 3 | (3 | ) | 2 | (3 | ) | 1 | 3 | ||||||||||||||||||||||||
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Total | $ | 126 | $ | 31 | $ | (7 | ) | $ | 4 | $ | (2 | ) | $ | 63 | $ | 26 | $ | 18 | $ | 17 | ||||||||||||||||
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Nine Months Ended September 30, 2015 | Three Months Ended March 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Merger and Integration Costs: | Exelon | Generation | ComEd | PECO | BGE | Exelon(a) | Generation(a) | ComEd | PECO | BGE | PHI(a) | Pepco(a) | DPL(a) | ACE(a) | ||||||||||||||||||||||||||||||||||||||||||
Financing(b) | $ | 21 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||||||
Transaction(c) | 14 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||
Transaction(b) | $ | 35 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||
Employee-Related(c) | 71 | 12 | 1 | 1 | 1 | 56 | 27 | 16 | 13 | |||||||||||||||||||||||||||||||||||||||||||||||
Other | 49 | 30 | 9 | 4 | 4 | (4 | ) | 4 | (9 | ) | 1 | 1 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||
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Total | $ | 84 | $ | 30 | $ | 9 | $ | 4 | $ | 4 | $ | 102 | $ | 16 | $ | (8 | ) | $ | 2 | $ | 2 | $ | 56 | $ | 27 | $ | 16 | $ | 13 | |||||||||||||||||||||||||||
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(a) | For Exelon, Generation, PHI, Pepco, DPL, and ACE, includes the operations of the acquired businesses beginning on March 24, 2016. |
(b) |
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External, third party costs paid to advisors, consultants, lawyers and other experts to assist in the due diligence and regulatory approval processes and in the closing of transactions. |
Costs primarily for employee severance, pension and OPEB expense and retention bonuses. |
Costs to integrate PHI processes and systems into Exelon. For the |
As of September 30, 2016,March 31, 2017, Exelon expects to incur total PHI acquisition and integration related costs of approximately $700 million, excluding merger commitments. Of this amount, including costs incurred from 2014 and through September 30, 2016,March 31, 2017, Exelon and PHI have incurred approximately $560$640 million. Included in this amount are costs to fund the merger of which $76 million has been expensed, $56 million has been paid and recorded as deferred debt issuance costs and $60 million has been incurred and charged to common stock. The remaining costs will be primarily within Operating and maintenance expense within Exelon’s Consolidated Statements of Operations and Comprehensive Income and will also include approximately $60$25 million for integration costs expected to be capitalized to Property, plant and equipment.
Significant 2017 Transactions and Developments
Acquisition of James A. FitzPatrick Nuclear Generating Station
On March 31, 2017, Generation acquired the 838 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station for a total purchase price of $293 million. In accounting for the acquisition as a business combination, Exelon and Generation recorded anafter-tax bargain purchase gain of $226 million which is included within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information regarding the Generation’s acquisition of Fitzpatrick and related costs.
Generation Renewables Joint Venture Transaction
On March 31, 2017, ExGen Renewables Holdings, LLC, a wholly-owned subsidiary of Generation, entered into an arrangement to sell 49% of its sole membership interest of ExGen Renewables Partners, LLC, a newly formed owner and operator of approximately 1,296 megawatts of Generation’s operating wind and solar electric generating facilities. This portfolio consists of 30 different projects located in 13 states and represents approximately 34.9% of Generation’s renewable generation assets and 4.0% of Generation’s total generation assets. The purchase price is $400 million, subject to certain working capital and other post-closing adjustments. These proceeds, net of approximately $115 million of income taxes on the sale, will be used by Generation to pay down debt and for general corporate purposes. Upon consummation of the transaction, ExGen Renewables Holdings will be the managing member and haveday-to-day control and management over the joint venture and its renewable generation portfolio. Consummation of the transaction is expected in the late second quarter or early third quarter and is subject to various customary closing conditions, including receipt of regulatory approvals from the Federal Energy Regulatory Commission and Public Utility Commission of Texas.
Distribution Formula Rate
On April 13, 2017, ComEd filed its annual distribution formula rate with the ICC pursuant to EIMA. The filing establishes the revenue requirement used to set the rates that will take effect in January 2018 after the ICC’s review and approval, which is due by December 2017. The revenue requirement requested is based on 2016 actual costs plus projected 2017 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2016 to the actual costs incurred that year. ComEd’s 2017 filing request includes a total increase to the revenue requirement of $96 million, reflecting an increase of $78 million for the initial revenue requirement for 2017 and a increase of $18 million related to the annual reconciliation for 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further information related to distribution formula rate updates.
Illinois Future Energy Jobs Act
On December 7, 2016, FEJA was signed into law by the Governor of Illinois. FEJA is effective June 1, 2017, and includes, among other provisions, (1) a ZES providing compensation for certain nuclear-powered generating facilities, (2) an extension of and certain adjustments to ComEd’s electric distribution formula rate, (3) new cumulative persisting annual energy efficiency MWh savings goals for ComEd, (4) revisions to the Illinois RPS requirements, (5) provisions for adjustments to or termination of FEJA programs if the average impact on ComEd’s customer rates exceeds specified limits, (6) revisions to the existing net metering statute to (i) mandate net metering for community generation projects, and establish billing procedures for subscribers to those projects, (ii) provide immediately for netting at the energy-only rate for nonresidential customers, and (iii) transition from netting at the full retail rate to the energy-only rate for certain residential net metering customers once the net meter customer load equals 5% of total peak demand supplied in the previous year and (7) support for low income rooftop and community solar programs. FEJA establishes new or adjusts existing rate recovery mechanisms for ComEd to recover costs associated with the new or expanded energy efficiency and RPS requirements. Regulatory or legal challenges over the validity of FEJA are possible. See Note 5 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional
information regarding FEJA. See Note 7 — Early Nuclear Plant Retirements of the PHI acquisition.Combined Notes to the Consolidated Financial Statements for the impacts of ZES on Generation’s Consolidated Balance Sheets and Consolidated Statements of Operations and Comprehensive Income.
Pepco Maryland Electric Distribution Rates
On March 24, 2017, Pepco filed an application with the MDPSC requesting an increase of $69 million based on a ROE of 10.1%. The application includes a request for an income tax adjustment to reflect full normalization of removal costs associated withpre-1981 property, which accounts for $18 million of the requested increase. Pepco expects a decision in the matter in the fourth quarter of 2017, but cannot predict how much of the requested rate increase the MDPSC will approve or if it will approve the requested income tax adjustment.
DPL Maryland Electric Distribution Rates
On February 15, 2017, the MDPSC approved an increase in DPL electric distribution rates of $38 million based on a ROE of 9.6%. The new rates became effective for services rendered on or after February 15, 2017. The MDPSC also denied DPL’s request to continue its Grid Resiliency Program, through which DPL proposed to invest $4.6 million a year for two years to improve priority feeders and install single-phase reclosing fuse technology. The final order did not result in the recognition of any incremental regulatory assets or liabilities during the first quarter of 2017.
DPL Delaware Electric and Natural Gas Distribution Rates
On March 8, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate, Delaware Electric Users Group and the DPSC Staff in its electric distribution rate proceeding, which provides for an increase in DPL electric distribution rates of $31.5 million based on an ROE of 9.7%. The settlement agreement also provides that the rates currently in effect, as approved by the DPSC, effective July 16, 2016 and December 17, 2016, will remain in effect until the date of the final DPSC order and that no refund will be required. As a result, during the first quarter of 2017, DPL established a regulatory asset of $8 million for costs incurred to achieve the merger and reversed a regulatory liability of $1 million for electric revenues that are no longer subject to refund which resulted in an increase in net income of $5 million. DPL currently expects a final order on the settlement agreement during the second quarter of 2017.
On April 6, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate and the DPSC Staff in its natural gas distribution rate proceeding, which provides for an increase in DPL natural gas distribution rates of $4.9 million based on an ROE of 9.7%. The settlement agreement also provides that DPL will refund amounts in excess of the $4.9 million increase collected under the temporary rates effective July 16, 2016 and December 17, 2016, and that the new rates will be effective within thirty days of DPSC approval of the settlement agreement. In the event that the final order reflects the settlement agreement, DPL does not expect the impact to be material to its financial statements. DPL currently expects a final order on the settlement agreement during the second quarter of 2017.
ACE New Jersey Electric Distribution Rates
On March 30, 2017, ACE submitted an application with the NJBPU to increase its electric distribution rates by approximately $70 million (before New Jersey sales and use tax), based upon a requested ROE of 10.1%. The application also requests approval of a rate surcharge mechanism called the “System Renewal Recovery Charge,” which would permit accelerated recovery of certain costs associated with reliability and system renewal-related capital investments. ACE currently expects a decision in this matter in the first quarter of 2018, but cannot predict if the NJBPU will approve the application as filed.
Transmission Formula Rate
The following total increases/(decreases) were included in ComEd’s and BGE’s electric transmission formula rate filings:
2017 | ||||||||
Annual Transmission Filings(a) | ComEd | BGE | ||||||
Initial revenue requirement increase | $ | 44 | $ | 31 | ||||
Annual reconciliation (decrease) increase | (33 | ) | 3 | |||||
Dedicated facilities decrease(b) | — | (8 | ) | |||||
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Total revenue requirement increase | $ | 11 | $ | 26 | ||||
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Allowed return on rate base(c) | 8.43 | % | 7.47 | % | ||||
Allowed ROE(d) | 11.50 | % | 10.50 | % |
(a) | All rates are effective June 2017, subject to review by the FERC and other parties, which is due by fourth quarter 2017. |
(b) | BGE’s transmission revenues include a FERC approved dedicated facilities charge 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% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, the rate of return on common equity is 10.50%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization. |
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate would be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. PECO cannot predict how much, if any, of a transmission rate increase FERC may approve or when the rate increase may go into effect.
Westinghouse Electric Company LLC Bankruptcy
On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. In the petitions and supporting documents, Westinghouse makes clear that its requests for relief center on one business area that is losing money — the construction of nuclear power plants in Georgia and South Carolina. Through the bankruptcy, Westinghouse seeks to reorganize around its profitable core business, which includes nuclear fuel fabrication and related services and other services provided to existing nuclear power plants in the U.S. and around the world. For these reasons, at this time, Generation does not anticipate disruption to the Westinghouse fuel fabrication contracts for Braidwood, Byron, or Ginna or other existing contracts for Generation’s nuclear power plants. Generation is monitoring the bankruptcy proceeding to ensure that its rights are protected.
Merger Commitment Unrecognized Tax Benefits
Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation in 2012 and PHI in
2016. In the first quarter 2017, as a part of its examination of Exelon’s return, the IRS National Office issued guidance concurring with Exelon’s position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million, and $22 million, respectively, as of March 31, 2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.
EGTP Consent Agreement
In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan. On May 2, 2017, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly-owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of administering the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP, including the revolving credit facility. As a result, in the second quarter, Exelon and Generation will reclassify certain EGTP’s assets and liabilities on Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. Exelon and Generation estimate a pre-tax impairment charge upon reclassification ranging from $300 million to $400 million will be recognized in the second quarter of 2017. See Note 10 — Debt and Credit Agreements and Note 20 — Subsequent Events for additional information regarding EGTP and the associated nonrecourse debt.
Exelon’s Strategy and Outlook for the remainder of 20162017 and Beyond
Exelon’s value proposition and competitive advantage come from its scope and its core strengths of operational excellence and financial discipline. Exelon leverages its integrated business model to create value. Exelon’s regulated and competitive businesses feature a mix of attributes that, when combined, offer shareholders and customers a unique value proposition:
Exelon’s utilities provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.
Generation’s competitive businesses provide free cash flow to support investmentinvest primarily in Exelon’sthe utilities and in long-term, contracted assets at Generation, and debt reduction.to reduce debt.
Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Exelon utilities only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Exelon utilities make these investments prudently and at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart meter technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and generation to load matching to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer facingcustomer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at
high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Several nuclear units within the Exelon fleet and nationally are economically challenged, threatened by persistently low prices and out-of-market payments to select generation sources. Some units have already retired prematurely for economic reasons, and Exelon has announced the planned early shutdown of its Clinton and Quad Cities units. Other Exelon units face similar challenges, most notably Ginna, Nine Mile Point and TMI. In August 2016, the New York Public Service Commission issued an order adopting the Clean Energy Standard (CES), designed to provide payments under a Zero Emissions Credit program to Generation’s Ginna and Nine Mile Point and Entergy’s James A. FitzPatrick nuclear plants in recognition of the environmental benefits of their zero emissions attributes. Exelon is working to develop other potential solutions at the state, federal and RTO levels so that markets and/or the states more appropriately value the carbon-free emission attribute of nuclear generation.
Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. Exelon’s Board of Directors has approved a revised dividend policy. The approved policy raises our dividendproviding a raise of 2.5% each year for the next three years, beginning with the June 2016 dividend.
Various market, financial, regulatory, legislative and otheroperational factors could affect the Registrants’ success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. See ITEM 1A. RISK FACTORS of the Exelon 20152016 Form10-K for additional information regarding market and financial factors.
Continually optimizing the cost structure is a key component of Exelon’s financial strategy. Through a recent focused cost management program, the company has committed to reducing operation and maintenance expenses and capital costs by approximately $350 million and $50 million, respectively, of which approximately 35% of run-rate savings was achieved by the end of 2016. Approximately 60% ofrun-rate savings are expected to be achieved by the end of 20162017 and fully realized in 2018. At least 75% of the savings are expected to be allocatedrelated to Generation, with the remaining amount allocatedrelated to the Utility Registrants. Exelon anticipates the earnings per share savings impact on EPS will be within $0.13 to $0.18 from 2018 forward.
Early Nuclear Plant RetirementsGrowth Opportunities
ExelonManagement continually evaluates growth opportunities aligned with Exelon’s businesses, assets and Generation continuemarkets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses.The PHI merger provides an opportunity to evaluate the current and expected economic value of each of Generation’s nuclear plants. Factors that will continue to affect the economic value of Generation’s nuclear plants include, but are not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure nuclear plants are fairly compensated for their carbon-free emissions, and the impact of final rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules.
In 2015, Generation identified the Quad Cities, Clinton and Ginna nuclear plants as having the greatest risk of early retirement based on economic valuation and other factors. At that time, Exelon and Generation deferred retirement decisions on Clinton and Quad Cities until 2016 in order to participate in the 2016-2017 MISO primary reliability auction and the 2019-2020 PJM capacity auctions held in April and May 2016, respectively, as well asaccelerate Exelon’s regulated growth to provide Illinois policy makers with additional timestable cash flows, earnings accretion, and dividend support. Additionally, the Utility Registrants anticipate investing approximately $25 billion over the next five years in electric and natural gas infrastructure improvements and modernization projects, including smart meter and smart grid initiatives, storm hardening, advanced reliability technologies, and transmission projects, which is projected to consider needed reforms and for MISOresult in an increase to consider market design changes to ensure long-term power system reliability in southern Illinois.
In April 2016, Clinton cleared the MISO primary reliability auction as a price taker for the 2016-2017 planning year. The resulting capacity price is insufficient to cover cash operating costs and a risk-adjustedcurrent rate base of return to shareholders. In May 2016, Quad Cities did not clear in the PJM capacity auction for the 2019-2020 planning year and will not receive capacity revenue for that period.
Based on these capacity auction results, and given the lack of progress on Illinois energy legislation and MISO market reforms, on June 2, 2016 Generation announced it will move forward to shut down the Clinton and Quad Cities nuclear plants on June 1, 2017 and June 1, 2018, respectively. The current Nuclear Regulatory Commission (NRC) licenses for Clinton and Quad Cities expire in 2026 and 2032, respectively. Generation is proceeding with the market and regulatory notifications that must be made to shut down the plants, including notification to the NRC on June 20, 2016, and filing of a deactivation notice with PJM for Quad Cities on July 6, 2016. Generation will formally notify MISO of its plans to close Clinton later this year.
In 2016, as a result of the plant retirement decision for Clinton and Quad Cities, Exelon and Generation recognized one-time charges in Operating and maintenance expense of $146 million related to materials and supplies inventory reserve adjustments, employee-related costs and construction work-in-progress (CWIP) impairments, among other items. In addition to these one-time charges, there will be ongoing annual incremental non-cash charges to earnings stemming from shortening the expected economic useful life of Clinton and Quad Cities primarily related to accelerated depreciation of plant assets (including any asset retirement costs (ARC)), accelerated amortization of nuclear fuel, and additional asset retirement obligation (ARO) accretion expense associated with the changes in decommissioning timing and cost assumptions. Exelon’s and Generation’s third quarter 2016 results include an incremental $443 million of pre-tax expense for these items. The following table summarizes the estimated annual amount and timing of such expected incremental non-cash expense items through 2018.
September 30, 2016 | Projected(a) | |||||||||||||||
Income statement expense (pre-tax) | 2016 | 2017 | 2018 | |||||||||||||
Depreciation and Amortization | ||||||||||||||||
Accelerated depreciation(b) | $ | 459 | $ | 800 | $ | 860 | $ | 200 | ||||||||
Accelerated nuclear fuel amortization | 37 | 70 | 75 | 20 | ||||||||||||
Operating and Maintenance | ||||||||||||||||
Increase ARO accretion, net of contractual offset(c) | 2 | 5 | 5 | 5 | ||||||||||||
Contractual offset for ARC depreciation(c) | (55 | ) | (100 | ) | (160 | ) | (60 | ) | ||||||||
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Total | $ | 443 | $ | 775 | $ | 780 | $ | 165 | ||||||||
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Please refer to Note 12 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional detail on changes to the Nuclear decommissioning ARO balances resulting from the early retirement of Clinton and Quad Cities.
The Three Mile Island (TMI) nuclear plant also did not clear in the May 2016 PJM capacity auction for the 2019-2020 planning year and will not receive capacity revenue for that period. This is the second consecutive year that TMI failed to clear the capacity auction. Although the plant is committed to operate through May 2019, the plant faces continued economic challenges and Exelon and Generation are exploring all options to return it to profitability. While a portion of the Byron nuclear plant’s capacity did not clear the PJM 2019-2020 planning year capacity auction, the plant is committed to run through May 2020. The company’s other nuclear plants in PJM cleared in the auction, except Oyster Creek, which did not participate in the auction given Exelon’s and Generation’s previous commitment to cease operation of the Oyster Creek nuclear plantapproximately $9 billion by the end of 2019.2021. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.
In New York, the Ginna and Nine Mile Point nuclear plants continue to face significant economic challenges and risk of retirement before the end of each unit’s respective operating license period (2029 for Ginna and Nine Mile Point Unit 1, and 2046 for Nine Mile Point Unit 2). On August 1, 2016, the NYPSC issued an order adopting the Clean Energy Standard (CES), which would provide payments to Ginna and Nine Mile Point for the environmental attributes of their production. Subject to Ginna and Nine Mile Point entering into a satisfactory contract with NYSERDA, as required under the CES, and subject to prevailing over any administrative or legal challenges, the CES will allow Ginna and Nine Mile Point to continue to operate at least through the life of the program (March 31, 2029). The approved RSSA currently requires Ginna to continue
operating through the RSSA term expiring in March 2017. If Ginna does not plan to retire shortly after the expiration of the RSSA, notification of that effect was required to be filed with the NYPSC no later than September 30, 2016. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the CES. Negotiations with NYSERDA are ongoing and contract execution is currently targeted for completion in the fourth quarter of 2016. Refer toSee Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional discussioninformation on the Ginna RSSASmart Meter and Smart Grid Initiatives and infrastructure development and enhancement programs.
Competitive Energy Businesses.Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to prioritize investments in long-term contracted generation across multiple technologies and identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, while identifying emerging technologies where strategic investments provide the option for significant future growth or influence in market development. As of March 31, 2017, Generation has currently approved plans to invest a total of approximately $600 million over the next two years to complete new plant construction currently in progress.
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 New York CES.use of other
financing structures (e.g., joint ventures, minority partners, etc.). The following table providesRegistrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.6 billion, $5.3 billion, $1 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion. See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities below.
For further detail regarding the balance sheet amountsRegistrants’ liquidity for the three months ended March 31, 2017, see Liquidity and Capital Resources discussion below.
Project Financing
Generation utilizes individual project financings as a means to finance the construction of September 30, 2016 for significantvarious generating asset projects. Project financing is based upon a nonrecourse financial structure, in which project debt and equity used to finance the project are paid back from the cash generated by the newly constructed asset once operational. Borrowings under these agreements are secured by the assets and liabilitiesequity 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 withdebt or other project-related borrowings earlier than the three nuclear plants currently considered by managementstated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to be atforeclose against the greatest risk of early retirementproject-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 current economic valuations and other factors.
(in millions) | TMI | Ginna | NMP | |||||||||
Asset Balances | ||||||||||||
Materials and supplies inventory | $ | 39 | $ | 31 | $ | 70 | ||||||
Nuclear fuel inventory, net | 93 | 41 | 214 | |||||||||
Completed plant, net | 956 | 124 | 1,151 | |||||||||
Construction work in progress | 38 | 13 | 53 | |||||||||
Liability Balances | ||||||||||||
Asset retirement obligation | (492 | ) | (667 | ) | (780 | ) | ||||||
NRC License Renewal Term | 2034 | 2029 | 2029 (unit 1 | ) | ||||||||
2046 (unit 2 | ) |
Assuming the successful implementationa higher likelihood of disposing of the CES and its continued effectiveness, Generation and CENG would no longer consider Ginna and Nine Mile Point to be at heightened risk of early retirement; however, absent the CES for the full expected duration they will remain at heightened risk. The precise timing of an early retirement date for any of these plants, and the resulting financial statement impacts, may be affected by a number of 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 decommissioning trust fund requirements, 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 obligations, where applicable, and just prior to its next scheduled nuclear refueling outage.
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 afterrespective project-specific assets significantly before the end of their useful lives. See Note 10 — Debt and Credit Agreements 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 contributionsCombined Notes to the NDT fundConsolidated Financial Statements for additional information on nonrecourse debt.
Other Key Business Drivers and Management Strategies
Utility Rates and Rate Proceedings
The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to ensure sufficient funds are available.their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position. See Note 125 — Nuclear Decommissioning toRegulatory Matters of the Combined Notes to Consolidated Financial Statements for additional informationfurther details on the NRC minimum funding requirements.
It is currently estimated that Clinton 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 investments could appreciate in value. Quad Cities is also at risk for such a shortfall. A shortfall could require Exelon to post parental guarantees for Generation’s share of the obligations. However, the amount of any required guarantees will ultimately depend on the decommissioning approach adopted at each site, the associated level of costs, and the decommissioning trust fund investment performance going forward. Within two years of shutting down a plant, Generation must submit a post-shutdown decommissioning activities report (PSDAR) to the NRC that includes the planned option for decommissioning the site. Considering the three alternative decommissioning approaches available for each site, the most costly estimates currently anticipated could require parental guarantees of up to $375 million for Clinton in order to access its NDT fund for radiological
decommissioning costs. Although Quad Cities is better positioned than Clinton to avoid the need for a parental guarantee, a guarantee of up to $110 million, at Generation’s ownership percentage, may be required in order for the site to access its NDT fund for radiological decommissioning costs. As of September 30, 2016, the additional plants at the highest risk of early retirement, Ginna, Nine Mile Point and TMI, pass the NRC minimum funding test based on their current license lives. However, in the event of an early retirement the most costly estimates currently anticipated could require parental guarantees of up to $115 million, $200 million, and $65 million for Ginna, Nine Mile Point and TMI, respectively, at Generation’s ownership percentages.
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, the NRC must approve an additional exemption in order for the plant’s owner(s) to utilize the NDT fund to pay for non-radiological decommissioning costs (i.e. spent fuel management and site restoration costs). If a unit does not receive this exemption, the costs would be borne by the owner(s). Accordingly, based on current projections, it is expected that some portion of the spent fuel management and/or site restoration costs would need to be funded through supplemental cash from Generation and others holding ownership interests. While the ultimate amounts may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the United States Department of Energy reimbursement agreements or future litigation, across the three alternative decommissioning approaches available, for the next 10 years, Clinton could incur spent fuel management and site restoration costs of up to $160 million, net of taxes. Quad Cities is better positioned to pass the test than Clinton. Although considered unlikely, if Quad Cities fails the exemption test, at its ownership percentage Generation could be required to pay for spent fuel management costs over the next ten years of up to $185 million, net of taxes, at Generation’s ownership percentage. If an early retirement decision is made and Ginna, Nine Mile Point, or TMI were to fail the exemption test, each could incur spent fuel management and site restoration costs over the next ten years of up to $60 million, $140 million and $145 million, net of taxes, respectively, at Generation’s ownership percentages.these regulatory proceedings.
Proposed Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)
On August 8, 2016, Generation executed a series of agreements with Entergy Nuclear FitzPatrick LLC (Entergy) to acquire the 838MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York for a cash purchase price of $110 million. As part of the transaction, Generation would receive the FitzPatrick NDT fund assets and assume the obligation to decommission FitzPatrick. Closing of the transaction is currently anticipated to occur in the second quarter of 2017 and is dependent upon regulatory approval by FERC, NRC and the New York Public Service Commission (NYPSC). The transaction is also subject to the notification and reporting requirements of the HSR Act (which has been completed) and other customary closing conditions. The NRC license for FitzPatrick expires in 2034. Entergy had previously announced plans in November 2015 to early retire FitzPatrick at the end of the current fuel cycle in January 2017. Under the terms of the agreements, Generation will reimburse Entergy for approximately $200 million to $250 million of incremental costs to refuel the plant and operate and maintain the plant after the refueling outage, scheduled to end in February 2017, through the closing date. These are costs which otherwise would have been avoided by FitzPatrick’s planned permanent shutdown in January 2017. Generation will be entitled to all revenues from FitzPatrick’s electricity and capacity sales for the period commencing upon completion of the refueling outage through the acquisition closing date. The agreements provide for certain termination rights, including the right of either party to terminate if the transaction has not been consummated within 12 months due to failure to obtain the required regulatory approvals.
On October 11, 2016, Public Citizen, Inc. filed a protest with FERC challenging Generation and Entergy’s application to FERC for the transfer of ownership of FitzPatrick. No other party to the proceeding has filed any protests or comments. Generation and Entergy had requested FERC to approve the FitzPatrick transaction by November 18, 2016, however FERC is under no obligation to do so. The timing of FERC’s decision on Generation and Entergy’s application and the outcome of this protest are currently uncertain. Refer to Note 5 — Regulatory Matters for additional information on the New York CES and ZEC program.
The transaction is expected to be accounted for as a business combination. For accounting and financial reporting purposes the costs that Generation reimburses Entergy for as well as the revenue received from Fitzpatrick prior to the close of the transaction will be treated as part of the purchase price consideration. Generation will record the fair value of the assets acquired and liabilities assumed as of the acquisition date. To the extent the purchase price is greater than the fair value of the net assets acquired, goodwill will be recorded. To the extent the fair value of the net assets acquired is greater than the purchase price, a bargain purchase gain will be recorded.
As of September 30, 2016, Generation has paid a non-refundable deposit of $10 million and reimbursed Entergy for $9 million in costs all of which have been classified with Other noncurrent assets on Exelon’s and Generation’s Consolidated Balance Sheets for a total amount of $19 million. These amounts are also reflected within Acquisition of businesses on Exelon’s and Generation’s Consolidated Statements of Cash Flows.
Power Markets
Price of Fuels. Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
Capacity Market Changes in PJM.PJM
In the wake of the January 2014 Polar Vortex that blanketed much of the Eastern and Midwestern United States, it became clear that while a major outage event was narrowly avoided, resources in PJM were not providing the level of reliability expected by customers. As a result, on December 12, 2014, PJM filed at FERC a proposal to make significant changes to its current capacity market construct, the Reliability Pricing Model (RPM). PJM’s proposed changes generally sought to improve resource performance and reliability largely by
limiting the excuses fornon-performance and by increasing the penalties for performance failures. The proposal permits suppliers to include in capacity market offers additional costs and risk so they can meet these higher performance requirements. While offers are expected to put upward pressure on capacity clearing prices, operational improvements made as a result of PJM’s proposal are expected to improve reliability, to reduce energy production costs as a result of more efficient operations and to reduce the need for out of market energy payments to suppliers. Generation participated actively in PJM’s stakeholder process through which PJM developed the proposal and also actively participated in the FERC proceeding including filing comments. On June 9, 2015, FERC approved PJM’s filing largely as proposed by PJM, including transitional auction rules for delivery years 2016/2017 through 2017/2018. As a result of this and several related orders, PJM hosted its 2018/2019 Base Residual Auction (results posted on August 21, 2015), and its transitional auction for delivery year 2016/2017 (results posted on August 31, 2015), and its transitional auction for delivery years 2017/2018 (results posted on September 9, 2015),. On May 10, 2016, FERC largely denied rehearing, and its 2019/2020 Base Residual Auction in May 2016. In June 2016, severala number of parties appealed the FERC’s decision approving PJM’s market changes to the U.S. Court of Appeals for the D. C. Circuit. Exelon has intervenedDC Circuit for review of the decision. It is too early in the matter in support of FERC’s decision. The outcome of thisprocess to predict the appeal is unclear at this time, but could impact earnings.outcome.
MISO Capacity Market Results. Results
On April 14, 2015, the Midcontinent Independent System Operator (MISO) released the results of its capacity auction covering the June 2015 through May 2016 delivery year. As a result of the auction, capacity prices for the zone 4 region in downstate Illinois increased to $150 per MW per day beginning in June 2015, an increase from the prior pricing of $16.75 per MW per day that was in effect from June 2014 to May 2015. Generation had an offer that was selected in the auction. However, due to Generation’s ratable hedging strategy, the results of the capacity auction have not had a material impact on Exelon’s and Generation’s consolidated results of operations and cash flows.
Additionally, in late May and June 2015, separate complaints were filed at the FERC by each of the State of Illinois, the Southwest Electric Cooperative, Public Citizens, Inc., and the Illinois Industrial Energy
Consumers challenging the results of this MISO capacity auction for the 2015/2016 delivery in MISO delivery zone 4. The complaints allegedallege generally that 1) the results of the capacity auction for zone 4 are not just and reasonable, 2) the results should be suspended, set for hearing and replaced with a new just and reasonable rate, 3) a refund date should be established and that 4) certain alleged behavior by one of the market participants other than Exelon or Generation, be investigated.
On October 1, 2015, the FERC announced that it was conducting anon-public investigation (that does not involve Exelon or Generation) into whether market manipulation or other potential violations occurred related to the auction. On December 31, 2015, the FERC issued a decision that certain of the rules governing the establishment of capacity prices in downstate Illinois are “not just and reasonable” on a prospective basis. The FERC ordered that certain rules must be changed forprior to the next auction scheduled in April 2016 thatauction which set capacity prices beginning June 1, 2016.for the 2016/2017 planning year. In response to this order, MISO filed conformingcertain rule changes with the FERC. TheOn March 18, 2016, FERC largely denied rehearing of its December 31, 2015 order. FERC continues to conduct itsnon-public investigation to determine if the April 2015 auction results were manipulated and, if so, whether refunds are appropriate. The FERC did establish May 28, 2015, the day the first complaint was filed, as the date from which refunds (if ordered) would be calculated, and it also made clear that the findings in the December 31, 2015 order do not prejudge the investigation or related proceedings. On March 18, 2016,Generation cannot predict the impact the FERC denied rehearingorder may ultimately have on future auction results, capacity pricing or decisions related to the potential early retirement of its December 31, 2015 order in this matter. On April 14, 2016, the MISO released the results of the 2016/2017 capacity auction; the zone 4 region in downstate Illinois cleared the auction at a rate of $72 per MW per day. Clinton nuclear plant, which operates in the zone 4 region, cleared the auctionhowever, such impacts could be material to Generation’s future results of operations and is committed to operate through May 31, 2017.cash flows. See Note 7 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on the impacts of the MISO announcement. On September 8, 2016, a coalition of MISO transmission customers filed a complaint alleging that the MISO failed to follow its tariff in conducting the capacity auction and, as a result, overstated the clearing prices including in zone 4 where the transmission customers allege that the rate should have been $20 per MW per day. Among other things, the transmission customers seek refunds of the alleged excess payment. It is too early in this proceeding to predict its outcome. Nonetheless, it could detrimentally impact the auction results for Clinton.
MISO has acknowledged the need for capacity market design changes in the zone 4 region and stated that reforms to its capacity market process may be required to drive future investment and is engaging stakeholders to consider such reforms. The FERC has also encouraged such efforts, and Exelon has been working with MISO and its stakeholders on such market changes.
Subsidized GenerationCompetitive Energy Businesses.Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to prioritize investments in long-term contracted generation across multiple technologies and identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, while identifying emerging technologies where strategic investments provide the option for significant future growth or influence in market development. As of March 31, 2017, Generation has currently approved plans to invest a total of approximately $600 million over the next two years to complete new plant construction currently in progress.
Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other
financing structures (e.g., joint ventures, minority partners, etc.). The rateRegistrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of expansion$0.6 billion, $5.3 billion, $1 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of subsidized generation, including low-carbon generation such$0.5 billion. See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities below.
For further detail regarding the Registrants’ liquidity for the three months ended March 31, 2017, see Liquidity and Capital Resources discussion below.
Project Financing
Generation utilizes individual project financings as winda means to finance the construction of various generating asset projects. Project financing is based upon a nonrecourse financial structure, in which project debt and solar energy,equity used to finance the project are paid back from the cash generated by the newly constructed asset once operational. 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 markets in which Generation’s output is sold can negatively impact wholesale power prices, and in turn, Generation’s resultsevent of operations.
Various states have attempteda default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to implement or propose legislation, regulationsaccelerate repayment of the associated debt or other policiesproject-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 inappropriately subsidize new generation developmentforeclose against the project-specific assets and existing generation which may result in artificially depressed wholesale energy and capacity prices.
For example, Exelon and others challengedrelated 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 constitutionality and other aspectsrespective project-specific assets significantly before the end of New Jersey legislation aimed at suppressing capacity market prices in federal court.their useful lives. See Note 510 — Regulatory Matters toDebt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for additional information on state specific actions taken in Marylandnonrecourse debt.
Other Key Business Drivers and New Jersey. Similar actions taken by the MDPSC were also challenged in federal court in an actionManagement Strategies
Utility Rates and Rate Proceedings
The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to which Exelon was not a party. The federal trial courts in both the New Jerseytheir electric transmission and Maryland actions effectively invalidated the actions taken by the New Jersey legislaturedistribution, and the MDPSC, respectively. Those decisions were upheld by the U.S. Court of Appeals. On April 19, 2016, the U.S. Supreme Court unanimously affirmed the Fourth Circuit decision holding that the MDPSC’s required contracts are illegal and unenforceable. On April 25, 2016, the U.S. Supreme Court denied certiorari concerning the Third Circuit decision. This denial of certiorari leaves the Third Circuit decision in place, with the same outcome as the Fourth Circuit decision.
Nonetheless, Exelon believes that these projects may have already artificially suppressed capacity prices in PJM in these auctions. While the Supreme Court decision is a positive development, continuation of inappropriate state efforts, if successful and unabated in future capacity auctions, could continuegas distribution rates to result in artificially depressed wholesale capacity and/or energy prices. Other states could seek to establish similar programs, which could substantially impact Exelon’s market driven position and could have a significant effect on Exelon’s financial results of operations, financial position and cash flows.
One such state is Ohio, where state-regulated utility companies FirstEnergy Ohio (FE) and AEP Ohio (AEP) initiated actions at the Public Utilities Commission of Ohio (PUCO) to obtain approval for Riders that effectively allow these two companies to pass through to all customers in their service territories the differences betweenrecover their costs and market revenuesearn a fair return on PPAs entered into between the utility and its merchant generation affiliate. Collectively more than 6,000MW of primarily coal-fired generation owned by FE and AEP’s affiliates sought ratepayer guaranteed subsidies via the proposed Riders. While AEP and FE initially filed for approvaltheir investments. The outcomes of these Riders in 2013regulatory proceedings impact the Utility Registrants’ current and 2014, respectively, it was not until late 2015 that the proposals obtained meaningful traction when PUCO staff entered into a settlement and stipulation with the Ohio utilities supporting the proposals and recommending that the PUCO approve the Riders. On March 31, 2016, PUCO issued separate orders generally approving each of the FE and AEP arrangements. In addition, separate complaints were filed at the FERC pursuing federal causes of action (i) seeking to impose affiliate self-dealing requirements on the PPAs and (ii) seeking to impose a MOPR on the resources supporting the PPAs. On April 27, 2016, the FERC issued orders on the affiliate matter rescinding certain affiliate waivers previously granted to AEP and FE and requiring each to demonstrate that the PPAs (prior to transacting under them) were entered into on an arms-length basis and do not reflect any affiliate preference. As a result, we do not believe that the PPAs impacted the results of PJM’s recently completed capacity auctions. Nonetheless, further action by AEP and FE related to the PPAs is possible. Indeed, FE recently filed a restructured arrangement at PUCO that appears to achieve a similar result without relying on a PPA. In addition, the outcome of the MOPR complaint and its impact, if any, on Generation is not yet clear as it is too early in the proceeding to predict its outcome. Finally, Dayton Power and Light filed at PUCO seeking approval of similar arrangements.
Exelon continues to monitor developments in Ohio, Maryland, New Jersey, New England and other states and participates in stakeholder and other processes to ensure that only appropriate state subsidies are developed. Exelon remains active in advocating for competitive markets, while opposing policies that require taxpayers and/ or consumers to subsidize or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid.
Energy Demand. Modest economic growth partially offset by energy efficiency initiatives is resulting in positive growth for electricity for Pepco, a decrease in projected load for electricity for BGE, DPL and ACE, and an essentially flat projected load for electricity for ComEd and PECO. ComEd, PECO,BGE, Pepco, DPL and ACE are projecting load volumes to increase (decrease) by 0.4%, 0.0%, (1.4)%, 1.0%, (1.7)% and (1.6)%, respectively, in 2016 compared to 2015.
Retail Competition. Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. We expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.
Strategic Policy Alignment
Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades.
Exelon’s Board of Directors declared the first quarter 2016 dividends of $0.31 per share each on Exelon’s common stock. The first quarter 2016 dividend was paid on March 10, 2016.
Exelon’s Board of Directors declared the second quarter 2016 dividends of $0.318 per share each on Exelon’s common stock. The second quarter 2016 dividend was paid on June 10, 2016. The dividend increased from the first quarter amount to reflect the Board’s decision to raise Exelon’s dividend 2.5% each year for the next three years, beginning with the June 2016 dividend.
Exelon’s Board of Directors declared the third quarter 2016 dividends of $0.318 per share each on Exelon’s common stock. The third quarter 2016 dividend was paid on September 9, 2016.
Exelon’s Board of Directors declared the fourth quarter 2016 dividends of $0.318 per share each on Exelon’s common stock. The fourth quarter 2016 dividend is payable on December 9, 2016.
All future quarterly dividends require approval by Exelon’s Board of Directors.
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. Generation has hedges in place that significantly mitigate this risk for 2016 and 2017. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. As of September 30, 2016, the percentage of expected generation hedged for the major reportable segments is 98%-101%, 85%-88% and 54%-57% for 2016, 2017 and 2018, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options and swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.
Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel is 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, coal, oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 57% of Generation’s uranium concentrate requirements from 2016 through 2020 are supplied by three producers. 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 position.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses. The completed merger with PHI provides an opportunity to accelerate Exelon’s regulated growth to provide stable cash flows, earnings accretion, and dividend support. Additionally, the Utility Registrants anticipate investing approximately $25 billion over the next five years in electric and natural gas infrastructure improvements and modernization projects, including smart meter and smart grid initiatives, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $9 billion by the end of 2020. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made prudently and at the lowest reasonable cost to customers.
See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further details on these regulatory proceedings.
Power Markets
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
Capacity Market Changes in PJM
In the wake of the January 2014 Polar Vortex that blanketed much of the Eastern and Midwestern United States, it became clear that while a major outage event was narrowly avoided, resources in PJM were not providing the level of reliability expected by customers. As a result, on December 12, 2014, PJM filed at FERC a proposal to make significant changes to its current capacity market construct, the Reliability Pricing Model (RPM). PJM’s proposed changes generally sought to improve resource performance and reliability largely by
limiting the excuses fornon-performance and by increasing the penalties for performance failures. The proposal permits suppliers to include in capacity market offers additional costs and risk so they can meet these higher performance requirements. While offers are expected to put upward pressure on capacity clearing prices, operational improvements made as a result of PJM’s proposal are expected to improve reliability, to reduce energy production costs as a result of more efficient operations and to reduce the need for out of market energy payments to suppliers. Generation participated actively in PJM’s stakeholder process through which PJM developed the proposal and also actively participated in the FERC proceeding including filing comments. On June 9, 2015, FERC approved PJM’s filing largely as proposed by PJM, including transitional auction rules for delivery years 2016/2017 through 2017/2018. As a result of this and several related orders, PJM hosted its 2018/2019 Base Residual Auction (results posted on August 21, 2015) and its transitional auction for delivery year 2016/2017 (results posted on August 31, 2015) and its transitional auction for delivery years 2017/2018 (results posted on September 9, 2015). On May 10, 2016, FERC largely denied rehearing, and a number of parties appealed to the U.S. Court of Appeals for the DC Circuit for review of the decision. It is too early in the process to predict the appeal outcome.
MISO Capacity Market Results
On April 14, 2015, the Midcontinent Independent System Operator (MISO) released the results of its capacity auction covering the June 2015 through May 2016 delivery year. As a result of the auction, capacity prices for the zone 4 region in downstate Illinois increased to $150 per MW per day beginning in June 2015, an increase from the prior pricing of $16.75 per MW per day that was in effect from June 2014 to May 2015. Generation had an offer that was selected in the auction. However, due to Generation’s ratable hedging strategy, the results of the capacity auction have not had a material impact on Exelon’s and Generation’s consolidated results of operations and cash flows.
Additionally, in late May and June 2015, separate complaints were filed at the FERC by each of the State of Illinois, the Southwest Electric Cooperative, Public Citizens, Inc., and the Illinois Industrial Energy Consumers challenging the results of this MISO capacity auction for the 2015/2016 delivery in MISO delivery zone 4. The complaints allege generally that 1) the results of the capacity auction for zone 4 are not just and reasonable, 2) the results should be suspended, set for hearing and replaced with a new just and reasonable rate, 3) a refund date should be established and that 4) certain alleged behavior by one of the market participants other than Exelon or Generation, be investigated.
On October 1, 2015, FERC announced that it was conducting anon-public investigation (that does not involve Exelon or Generation) into whether market manipulation or other potential violations occurred related to the auction. On December 31, 2015, FERC issued a decision that certain of the rules governing the establishment of capacity prices in downstate Illinois are “not just and reasonable” on a prospective basis. FERC ordered that certain rules be changed prior to the April 2016 auction which set capacity prices for the 2016/2017 planning year. In response to this order, MISO filed certain rule changes with FERC. On March 18, 2016, FERC largely denied rehearing of its December 31, 2015 order. FERC continues to conduct itsnon-public investigation to determine if the April 2015 auction results were manipulated and, if so, whether refunds are appropriate. FERC did establish May 28, 2015, the day the first complaint was filed, as the date from which refunds (if ordered) would be calculated, and it also made clear that the findings in the December 31, 2015 order do not prejudge the investigation or related proceedings. Generation cannot predict the impact the FERC order may ultimately have on future auction results, capacity pricing or decisions related to the potential early retirement of the Clinton nuclear plant, however, such impacts could be material to Generation’s future results of operations and cash flows. See Note 7 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on the Smart Meter and Smart Grid Initiatives and infrastructure development and enhancement programs.impacts of the MISO announcement.
Competitive Energy Businesses.. Generation continually assesses the optimal structure and composition of ourits generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to prioritize investments in long-term contracted generation across multiple technologies and identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, while identifying emerging technologies where strategic investments provide the option for significant future growth or influence in market development. As of September 30, 2016,March 31, 2017, Generation has currently approved plans to invest a total of approximately $2 billion in 2016 through 2018 on capital growth projects (primarily$600 million over the next two years to complete new plant construction and distributed generation).currently in progress.
Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other
financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
The RegistrantsExelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have access to unsecured syndicated revolving credit facilities with aggregate bank commitments of $9.0 billion.$0.6 billion, $5.3 billion, $1 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $525 million.$0.5 billion. See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities below.
Exposure to Worldwide Financial Markets. Exelon has exposure to worldwide financial markets including European banks. Disruptions in the European markets could reduce or restrictFor further detail regarding the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of September 30, 2016, approximately 23%, or $2.2 billion, offor the Registrants’ aggregate total commitments were with European banks. The credit facilities include $9.5 billion in aggregate total commitments of which $7.9 billion was available as of September 30, 2016, due to outstanding letters of credit. There was $40 million of borrowings under the Registrants’ bilateral credit facilities as of September 30, 2016. Seethree months ended March 31, 2017, see Liquidity and Capital Resources discussion below.
Project Financing
Generation utilizes individual project financings as a means to finance the construction of various generating asset projects. Project financing is based upon a nonrecourse financial structure, in which project debt and equity used to finance the project are paid back from the cash generated by the newly constructed asset once operational. 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. See Note 10 — Debt and Credit Matters — Exelon Credit FacilitiesAgreements of the Combined Notes to the Consolidated Financial Statements for additional information.information on nonrecourse debt.
Other Key Business Drivers and Management Strategies
Utility Rates and Rate Proceedings
The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further details on these regulatory proceedings.
Power Markets
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
Capacity Market Changes in PJM
In the wake of the January 2014 Polar Vortex that blanketed much of the Eastern and Midwestern United States, it became clear that while a major outage event was narrowly avoided, resources in PJM were not providing the level of reliability expected by customers. As a result, on December 12, 2014, PJM filed at FERC a proposal to make significant changes to its current capacity market construct, the Reliability Pricing Model (RPM). PJM’s proposed changes generally sought to improve resource performance and reliability largely by
limiting the excuses fornon-performance and by increasing the penalties for performance failures. The proposal permits suppliers to include in capacity market offers additional costs and risk so they can meet these higher performance requirements. While offers are expected to put upward pressure on capacity clearing prices, operational improvements made as a result of PJM’s proposal are expected to improve reliability, to reduce energy production costs as a result of more efficient operations and to reduce the need for out of market energy payments to suppliers. Generation participated actively in PJM’s stakeholder process through which PJM developed the proposal and also actively participated in the FERC proceeding including filing comments. On June 9, 2015, FERC approved PJM’s filing largely as proposed by PJM, including transitional auction rules for delivery years 2016/2017 through 2017/2018. As a result of this and several related orders, PJM hosted its 2018/2019 Base Residual Auction (results posted on August 21, 2015) and its transitional auction for delivery year 2016/2017 (results posted on August 31, 2015) and its transitional auction for delivery years 2017/2018 (results posted on September 9, 2015). On May 10, 2016, FERC largely denied rehearing, and a number of parties appealed to the U.S. Court of Appeals for the DC Circuit for review of the decision. It is too early in the process to predict the appeal outcome.
MISO Capacity Market Results
On April 14, 2015, the Midcontinent Independent System Operator (MISO) released the results of its capacity auction covering the June 2015 through May 2016 delivery year. As a result of the auction, capacity prices for the zone 4 region in downstate Illinois increased to $150 per MW per day beginning in June 2015, an increase from the prior pricing of $16.75 per MW per day that was in effect from June 2014 to May 2015. Generation had an offer that was selected in the auction. However, due to Generation’s ratable hedging strategy, the results of the capacity auction have not had a material impact on Exelon’s and Generation’s consolidated results of operations and cash flows.
Additionally, in late May and June 2015, separate complaints were filed at the FERC by each of the State of Illinois, the Southwest Electric Cooperative, Public Citizens, Inc., and the Illinois Industrial Energy Consumers challenging the results of this MISO capacity auction for the 2015/2016 delivery in MISO delivery zone 4. The complaints allege generally that 1) the results of the capacity auction for zone 4 are not just and reasonable, 2) the results should be suspended, set for hearing and replaced with a new just and reasonable rate, 3) a refund date should be established and that 4) certain alleged behavior by one of the market participants other than Exelon or Generation, be investigated.
On October 1, 2015, FERC announced that it was conducting anon-public investigation (that does not involve Exelon or Generation) into whether market manipulation or other potential violations occurred related to the auction. On December 31, 2015, FERC issued a decision that certain of the rules governing the establishment of capacity prices in downstate Illinois are “not just and reasonable” on a prospective basis. FERC ordered that certain rules be changed prior to the April 2016 auction which set capacity prices for the 2016/2017 planning year. In response to this order, MISO filed certain rule changes with FERC. On March 18, 2016, FERC largely denied rehearing of its December 31, 2015 order. FERC continues to conduct itsnon-public investigation to determine if the April 2015 auction results were manipulated and, if so, whether refunds are appropriate. FERC did establish May 28, 2015, the day the first complaint was filed, as the date from which refunds (if ordered) would be calculated, and it also made clear that the findings in the December 31, 2015 order do not prejudge the investigation or related proceedings. Generation cannot predict the impact the FERC order may ultimately have on future auction results, capacity pricing or decisions related to the potential early retirement of the Clinton nuclear plant, however, such impacts could be material to Generation’s future results of operations and cash flows. See Note 7 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on the impacts of the MISO announcement.
Subsidized Generation
The rate of expansion of subsidized generation, in the markets in which Generation’s output is sold can negatively impact wholesale power prices, and in turn, Generation’s results of operations.
Various states have attempted to implement or propose legislation, regulations or other policies to subsidize new generation development which may result in artificially depressed wholesale energy and capacity prices. For example, the New Jersey legislature enacted into law in January 2011, the Long Term Capacity Pilot Program Act (LCAPP). LCAPP provides eligible generators with15-year fixed contracts for the sale of capacity in the PJM capacity market. Under LCAPP, the local utilities in New Jersey are required to pay (or receive) the difference between the price eligible generators receive in the capacity market and the price guaranteed under the15-year contract. New Jersey ultimately selected three proposals to participate in LCAPP and build new generation in the state. In addition, on April 12, 2012, the MDPSC issued an order directing the Maryland electric utilities to enter into a20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV was required to construct an approximately 700 MW combined cycle gas turbine in Waldorf, Maryland. The CfD mandated that utilities (including BGE, Pepco and DPL) pay (or receive) the difference between CPV’s contract price and the revenues it receives for capacity and energy from clearing the unit in the PJM capacity market.
Exelon and others challenged the constitutionality and other aspects of the New Jersey legislation in federal court. The actions taken by the MDPSC were also challenged in federal court in an action to which Exelon was not a party. The federal trial courts in both the New Jersey and Maryland actions effectively invalidated the actions taken by the New Jersey legislature and the MDPSC, respectively. Each of those decisions was upheld by the U.S. Court of Appeals for the Third Circuit and the U.S. Court of Appeals for the Fourth Circuit, respectively. On April 19, 2016, the U.S. Supreme Court affirmed the decision of the U.S. Court of Appeals for the Fourth Circuit, and subsequently denied certiorari with respect to the appeal from the U.S. Court of Appeals for the Third Circuit, leaving in place that Court’s decision. The matter is now considered closed.
As required under their contracts, generator developers who were selected in the New Jersey and Maryland programs (including CPV) offered and cleared in PJM’s capacity market auctions. To the extent that the state-required customer subsidies are included under their respective contracts, Exelon believes that these projects may have artificially suppressed capacity prices in PJM in these auctions and may continue to do so in future auctions to the detriment of Exelon. While the court decisions are positive developments, continuation of these state efforts, if successful and unabated by an effective minimum offer price rule (MOPR) for future capacity auctions, could continue to result in artificially depressed wholesale capacity and/or energy prices. Other states could seek to establish programs, which could substantially impact Exelon’s position and could have a significant effect on Exelon’s financial results of operations, financial position and cash flows.
One such state is Ohio, where state-regulated utility companies FirstEnergy Ohio (FE) and AEP Ohio (AEP) initiated actions at the Public Utilities Commission of Ohio (PUCO) to obtain approval for Riders that would effectively allow these two companies to pass through to all customers in their service territories the differences between their costs and market revenues on PPAs entered into between the utility and its merchant generation affiliate for what was collectively more than 6,000MW of primarily coal-fired generation. Thus, the Riders were similar to the CfDs described above (except that the PPA Riders in Ohio would apply to existing generation facilities whereas the CfDs applied to new generation facilities). While FERC orders on April 27, 2016 largely alleviated the concerns related to the Riders by holding that the PPAs ran afoul of affiliate restrictions on FE and AEP, we continue to closely monitor developments in Ohio.
In addition, Exelon continues to monitor developments in Maryland, New Jersey, and other states and participates in stakeholder and other processes to ensure that similar state subsidies are not developed. Exelon remains active in advocating for competitive markets, while opposing policies that require taxpayers and/ or consumers to subsidize or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid.
Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs
PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to remove the revenues it receives through a federal, state or other 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 resources. Exelon has generally opposed policies that required subsidies or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid. Thus, Exelon has supported a MOPR as a means of minimizing the detrimental impact of certain subsidized resources could have on capacity markets (such as the New Jersey (LCAPP) and Maryland (CfD) programs. However, in Exelon’s view, MOPRs should not be applied to resources that receive compensation for providing superior reliability or environmental benefits.
On January 9, 2017, the Electric Power Supply Association (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. Both filings allege that the relevant MOPR should be expanded to also apply to existing resources receiving ZEC compensation under the New York CES and Illinois ZES programs. Exelon has filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS that have generally not been subject to a MOPR. However, if successful, for Generation’s facilities expected to receive ZEC compensation (Quad Cities, Ginna, Nine Mile Point and FitzPatrick), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in those auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any such mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. The timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.
Energy Demand
Modest economic growth partially offset by energy efficiency initiatives is resulting in flat to declining load growth in electricity for the utilities. There is a decrease in projected load for electricity for ComEd, PECO, BGE, and ACE, and an essentially flat projected load for electricity for DPL. ComEd, PECO, BGE, Pepco, ACE and DPL are projecting load volumes to increase (decrease) by (0.1)%, (0.2)%, (2.4)%, (1.4)%, (1.9)%, and 0.0% respectively, in 2017 compared to 2016.
Retail Competition
Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. The market experienced high price volatility in the first quarter of 2014 which contributed to bankruptcies and consolidations within the industry during the year. However, forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.
Strategic Policy Alignment
As part of its strategic business planning process, Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades.
Exelon’s board of directors declared first quarter 2017 dividends of $0.3275 per share on Exelon’s common stock. The first quarter 2017 dividend was paid on March 10, 2017. The dividend increased from fourth quarter 2016 amount to reflect the Board’s decision to raise Exelon’s dividend 2.5% each year for the next three years, beginning with the June 2016 dividend.
Exelon’s Board of Directors declared the second quarter 2017 dividends of $0.3275 per share each on Exelon’s common stock and is payable on June 9, 2017.
All future quarterly dividends require approval by Exelon’s Board of Directors.
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 intonon-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. Generation has hedges in place that significantly mitigate this risk for 2017 and 2018. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. As of March 31, 2017, the percentage of expected generation hedged for the major reportable segments was97%-100%,60%-63% and30%-33% for 2017, 2018, and 2019 respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options and swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.
Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel is 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, coal, oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potentialnon-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 49% of Generation’s uranium concentrate requirements from 2017 through 2021 are supplied by three producers. In the event ofnon-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 position.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Tax Matters
Potential Corporate Tax Reform
The results of the November 2016 U.S. elections have introduced greater uncertainty with respect to federal tax policies. President Trump has stated that one of his top priorities is comprehensive tax reform and House Republicans plan to advance their tax reform “blueprint”. Tax reform proposals call for a reduction in the corporate federal income tax rate from the current 35% to as low as 15%. Other proposals provide, among other items, for the immediate deduction of capital investment expenditures and full or partial elimination of debt interest expense deductions. It is uncertain whether, to what extent or when these or any other changes in federal tax policies will be enacted or the transition time frame for such changes. Further, for the Utility Registrants,
regulators may impose rate reductions to provide the benefit of any income tax expense reductions to customers and refund “excess” deferred income taxes previously collected through rates. The amounts and timing of any such rate changes would be subject to the discretion of the rate regulator in each specific jurisdiction. For these reasons, the Registrants cannot predict the impact any potential changes may have on their future results of operations, cash flows or financial position, and such changes could be material.
See Note 11 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for additional information.information
Environmental Legislative and Regulatory Developments
Exelon iswas actively involved in the EPA’sObama Administration’s development and implementation of environmental regulations for the electric industry, in pursuit of its business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on fossil-fuelcoal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Retirements of coal-fired power plants are expected to continue as additional EPA regulations take effect, and as air quality standards are updated and further restrict emissions. Due to its low emission generation portfolio, Generation willhas not bebeen significantly directly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil-fuel plants. Various bills have been introduced in
Through the U.S. Congress that would prohibit or impede the EPA’s rulemaking efforts, and it is uncertain whether anyissuance of these bills will become law.
Air Quality. In recent years, the EPA has been implementing a series of increasinglyExecutive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.
In particular, the Administration has targeted existing EPA regulations underfor repeal, including notably the Clean AirPower Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings, and withdrew all technical support documents supporting the calculation. Other regulations that have been specifically identified for review are the Clean Water Act applicablerule relating to electric generating units. These regulations have resulted in more stringent emissions limits on fossil-fuel electric generating stations as states implement their compliance plans.
jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the 2015 National Ambient Air Quality StandardsStandard (NAAQS). for ozone. The EPA continues to review of final rules could extend over several years as formal notice and update its NAAQS for conventional air pollutants relating to ground-level ozone and emissions of particulate matter, SO2 and NOx. Following five years of litigation, the EPA is finalizing the Cross State comment rulemaking process proceeds.
Air Pollution Rule that requires 28 upwind states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in downwind states.Quality
Mercury and Air Toxics Standard Rule (MATS). On December 16, 2011, the EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. The initial compliance deadline to meet the new standards was April 16, 2015; however, facilities may have been granted an additional one or two year extension in limited cases. Numerouscases.Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate hazardous air pollutants emitted by electric utilities. The U.S. Supreme Court, however, did not vacate the rule; rather, it was remanded to the D.C. Circuit Court to take further action
consistent with the U.S. Supreme Court’s opinion on this single issue. As such, the MATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule.
Climate Change. Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In the absence of federal legislation, the EPA is moving forward with the regulation of GHG emissions under the Clean Air Act. In addition, there have been recent developments in the international regulation of GHG emissions pursuant to the United Nations Framework Convention on Climate Change (“UNFCCC” or “Convention”). On October 5, 2016, the Paris Climate Change Agreement entered into effect, and the next meeting of the Conference of the Parties in November 2016 will address procedural issues as countries take action to meet their voluntary carbon emission reductions. See ITEM 1. BUSINESS, “Global Climate Change” of the Exelon 2015 Form 10-K for further discussion.
Water Quality. Quality
Section 316(b) of the Clean Water Act requires that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by changes to the existing regulations. Those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, Fitzpatrick, Ginna, Gould Street, Handley, Mountain Creek, Mystic 7, Nine Mile Point Unit 1, Oyster Creek, Peach Bottom, Quad Cities, SalemRiverside and Wolf Hollow.Salem. See ITEM 1. — BUSINESS, “Water Quality” of the Exelon 20152016 Form 10-K for further discussion.
Solid and Hazardous Waste. Waste
In October 2015, the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants became effective. The rule classifies CCR asnon-hazardous waste under RCRA. Under the regulation, CCR will continue to be regulated by most states subject to coordination with the federal regulations. Generation has previously recorded reservesaccruals consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted under the new federal regulations for coal ash disposal sites formerly owned by Generation. For these reasons, Generation is unable to predict whether and to what extent it may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations.
See Note 1817 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters, including the impact of environmental regulation.
Other Regulatory and Legislative Actions
NRC Task Force Insights from the Fukushima Daiichi Accident (Exelon and Generation). In July 2011, an NRC Task Force formed in the aftermath of the March 11, 2011, 9.0 magnitude earthquake and ensuing tsunami, that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, issued a report of its review of the accident, including tiered recommendations for future regulatory action by the NRC to be taken in the near and longer term. The Task Force’s report concluded that nuclear reactors in the United States are operating safely and do not present an imminent risk to public health and safety. The NRC and its staff have issued orders and implementation guidance for commercial reactor licensees operating in the United States. The NRC and its staff are continuing to evaluate additional requirements. Generation has assessed the impacts of the Tier 1 orders and information requests and will continue monitoring the additional recommendations under review by the NRC staff, both from an operational and a financial impact standpoint. A comprehensive review of the NRC Tier 1 orders and information requests, as well as preliminary engineering assumptions and analysis, indicate that the financial impact of compliance for Generation, net of expected co-owner reimbursements, for the period from 2016 through 2019 is expected to be between approximately $150 million and $175 million of capital (which includes approximately $25 million for the CENG plants) and $25 million of operating expense (which includes approximately $5 million for the CENG plants). These revised amounts take into consideration the effect of the early plant retirements of Clinton and Quad Cities (see Note 7—Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information). Generation’s current assessments are specific to the Tier 1 recommendations as the NRC has not finalized actions with respect to the Tier 2 and Tier 3 recommendations. Exelon and Generation are unable to conclude at this time to what extent any actions to comply with the requirements of Tier 2 and Tier 3 will impact their future financial position, results of operations, and cash flows. Generation will continue to engage in nuclear industry assessments and actions and stakeholder input.
New York Clean Energy Standard (Exelon, Generation).On August 1, 2016, the the New York Public Service Commission (NYPSC) issued an order establishing the Clean Energy Standard (CES), a component of which includes creation of a Tier 3 Zero Emission Credit (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. The New York State Energy Research and Development Authority (NYSERDA) will centrally procure the ZECs from eligible plants through a 12-year contract, to be administered in six two-year tranches, extending from April 1, 2017 through March 31, 2029. ZEC payments will be made to the eligible resources based upon the number of MWh produced, subject to specified caps and minimum performance requirements. The price to be paid for the ZECs under each tranche will be administratively determined using a formula based on the social cost of carbon as determined by the federal government. The ZEC price for the first tranche has been set at $17.48 per MWh of production. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) shall be required to purchase an amount of ZECs equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers shall be incorporated into the commodity charges on customer bills. The CES initially identifies the three plants eligible for the ZEC program to include, for now, the FitzPatrick, Ginna, and Nine Mile Point nuclear facilities. The program specifically provides that Nine Mile Point Units 1 & 2 qualify jointly as a single facility and if either unit permanently ceases operations then both units will no longer qualify for ZEC payments for the remainder of the program. As issued, the order provides that the duration of the program beyond the first tranche is conditional upon a buyer purchasing the FitzPatrick facility and taking title prior to September 1, 2018; however, Generation and CENG requested clarification, or in the alternative limited rehearing, that this condition is applicable to the FitzPatrick facility only and has no bearing on the 12-year duration of the program for Ginna or Nine Mile Point. To date, several parties have filed with the NYPSC requests for rehearing or reconsideration of the CES and 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. Generation and CENG will seek to intervene in the case and to dismiss the lawsuit. Other legal challenges remain possible and the outcomes of each of these challenges is currently uncertain. Negotiations with NYSERDA regarding contracts for the sale of ZECs from Ginna, Nine Mile Point and FitzPatrick are ongoing, and Generation expects that NYSERDA will enter into final agreements during the fourth quarter of 2016. See Note 7 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information relative to Ginna and Nine Mile Point and Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information on Generation’s proposed acquisition of FitzPatrick.
Illinois Low Carbon Portfolio Standard (Exelon, Generation and ComEd). In March 2015, the Low Carbon Portfolio Standard (LCPS) was introduced in the Illinois General Assembly. The legislation would require ComEd and Ameren to purchase low carbon energy credits to match 70 percent of the electricity used on the distribution system. The LCPS is a technology-neutral solution, so all generators of zero or low carbon energy would be able to compete in the procurement process, including wind, solar, hydro, clean coal and nuclear. Costs associated with purchasing the low carbon energy credits would be collected from customers. The LCPS proposal includes consumer protections such as a price cap that would limit the impact to a 2.015% increase based off 2009 monthly bills, or about $2 per month for the average residential electricity customer, similar to the cost cap protection under other clean energy programs in Illinois. The legislation also includes a separate customer rebate provision that would provide a direct bill credit to customers in the event wholesale prices exceed a specified level. The proposed legislation remains pending along with two other major energy bills. Exelon and Generation continue to work with stakeholders on a comprehensive energy package.
Legislation to Maximize Smart Grid Investments and to Promote a Cleaner and Greener Illinois (Exelon and ComEd).In March 2015, legislation was introduced in the Illinois General Assembly that would (1) build on ComEd’s investment in the Smart Grid to reinforce the resiliency and security of the electrical grid to withstand unexpected challenges, (2) expand energy efficiency programs to reduce energy waste and increase customer savings, (3) further integrate clean renewable energy onto the power system, and (4) introduce a new demand-based rate design for residential customers that would allow for a more equitable sharing of smart grid costs among customers. The legislation also provides for additional funding for customer assistance programs for low-income customers. The proposed legislation is pending and ComEd continues to work with stakeholders.
Next Generation Energy Plan (Exelon, Generation and ComEd). On May 5, 2016, the Next Generation Energy Plan was introduced in the Illinois General Assembly. The legislation contains significant parts of the previously introduced Illinois Low Carbon Portfolio Standard and Legislation to Maximize Smart Grid Investments and to Promote a Cleaner and Greater Illinois, along with new elements. The legislation includes (1) a Zero Emission Standard providing compensation for at-risk nuclear plants that demonstrate their revenues are insufficient to cover their costs, (2) $1 billion of funding for low-income assistance, including $650 million for energy efficiency programs, $250 million in Renewable Energy Resource Funds, $50 million in Percentage of Income Payment Plan funding and utility bill assistance, and $50 million in ComEd CARE, (3) $140 million in new funding for solar development and a new solar rebate to incent solar generation, (4) additional investment at ComEd to enhance reliability and security of the power grid, (5) an expansion of the Renewable Portfolio Standard, and (6) a 50% reduction in the fixed customer charge for energy delivery creating more equitable rates across customers. The proposed legislation is pending and Exelon, Generation, and ComEd continue to work with stakeholders. See Note 7 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information.
Distribution Formula Rate (Exelon and ComEd). On April 13, 2016, ComEd filed its annual distribution formula rate with the ICC, requesting a total increase to the revenue requirement of $138 million, reflecting an increase of $139 million for the initial revenue requirement for 2017 and a decrease of $1 million related to the annual reconciliation for 2015. The filing establishes the revenue requirement used to set the rates that will take effect in January 2017 after the ICC’s review and approval, which is due by December 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further information related to distribution formula updates.
2016 Maryland Electric Distribution Rate Case (Exelon, PHI and Pepco).On April 19, 2016, Pepco filed an application with the MDPSC requesting an increase of $127 million to its electric distribution base rates, which was later updated to $103 million, based on a requested ROE of 10.6%. The application is inclusive of a request seeking recovery of Pepco’s regulatory assets associated with its AMI program over a five-year period supported by evidence demonstrating that the benefits of the AMI program exceed the costs on a present value basis. Any adjustments to rates approved by the MDPSC are expected to take effect in November 2016. In addition to the proposed rate increase, Pepco is proposing to continue its Grid Resiliency Program initially approved in July 2013 in connection with Pepco’s electric distribution rate case filed in November 2012. Under the Grid Resiliency Program, Pepco is authorized to receive recovery of specific investments as the assets are placed in service through the Grid Resiliency Charge. In connection with the Grid Resiliency Program, Pepco proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse technology by investing $16 million a year for two years for a total of $32 million. Pepco cannot predict how much of the requested rate increase the MDPSC will approve or if it will approve a continuation of Pepco’s Grid Resiliency Program proposal.
2016 Maryland Electric Distribution Base Rates (Exelon, PHI and DPL).On July 20, 2016, DPL filed an application with the MDPSC requesting an increase of $66 million to its electric distribution base rates, which was later updated to $57 million, based on a requested ROE of 10.6%. The application is inclusive of a request seeking recovery of DPL’s regulatory assets associated with its AMI program over a five-year period supported by evidence demonstrating that the benefits of the AMI program exceed the costs on a present value basis. Any adjustments to rates approved by the MDPSC are expected to take effect in February 2017. DPL cannot predict how much of the requested increase the MDPSC will approve. In addition to the proposed rate increase, DPL is proposing to continue its Grid Resiliency Program initially approved in September 2013 in connection with DPL’s electric distribution rate case filed in February 2013. Under the Grid Resiliency Program, DPL is authorized to receive recovery of specific investments as the assets are placed in service through the Grid Resiliency Charge. In connection with the Grid Resiliency Program, DPL proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse technology by investing $4.6 million a year for two years for a total of $9.2 million. DPL cannot predict whether the MDPSC will approve a continuation of DPL’s Grid Resiliency Program proposal.
2016 Electric and Natural Gas Distribution Base Rates (Exelon, PHI and DPL). On May 17, 2016, DPL filed an application with the DPSC to increase its annual electric and natural gas distribution base rates by $63 million and $22 million, respectively, based on a requested ROE of 10.6%. While the DPSC is not required to issue a decision on the application within a specified period of time, Delaware law allows DPL to put into effect $2.5 million of the rate increase two months after filing the applications which were effective July 16, 2016. It also allows the entire requested rate increase seven months after filing, subject to a cap and a refund obligation based on the final DPSC order. DPL cannot predict how much of the requested increase the DPSC will approve.
2015 Maryland Electric and Natural Gas Distribution Rate Case (Exelon and BGE). On November 6, 2015, and as amended through the course of the proceeding, BGE filed for electric and natural gas base rate increases with the MDPSC, ultimately requesting annual increases of $116 million and $78 million respectively, of which $104 million and $37 million, were related to recovery of electric and natural gas smart grid initiative costs, respectively. BGE also proposed to recover an annual increase of approximately $30 million for Baltimore City underground conduit fees through a surcharge.
On June 3, 2016, the MDPSC issued an order in which the MDPSC found compelling evidence to conclude that BGE’s smart grid initiative overall was cost beneficial to customers. However, the June 3 order contained several cost disallowances and adjustments, including not allowing BGE to defer or recover through a surcharge the $30 million increase in annual Baltimore City underground conduit fees. On June 30, 2016, BGE filed a petition for rehearing of the June 3 order requesting that the MDPSC modify its order to reverse certain decisions including the decision associated with the Baltimore City underground conduit fees. OPC also subsequently filed for a petition for rehearing of the June 3 order.
On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustments related to the smart grid initiative. Through the combination of the orders, the MDPSC authorized electric and natural gas rate increases of $44 million and $48 million, respectively, and an allowed ROE for the electric and natural gas distribution businesses of 9.75% and 9.65%, respectively. The new electric and natural gas base rates took effect for service rendered on or after June 4, 2016. However, MDPSC’s July 29 order on the petition on rehearing still did not allow BGE to defer or recover through a surcharge the increase in Baltimore City underground conduit fees.
On August 26, 2016, BGE filed an appeal of the MDPSC’s orders with the Circuit Court for Baltimore County. On August 29, 2016, the residential consumer advocate also filed an appeal of the MDPSC’s order but with the Circuit Court for Baltimore City. Refer to the Conduit Lease with City of Baltimore disclosure below for further details about BGE’s efforts to protect its customers from any improper use by the City of the conduit fee revenues and to place constraints on the City’s ability to set the conduit fee in the future. Refer to Note 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further details on the impact of the ultimate disallowances contained in the orders to BGE.
2016 Electric Distribution Base Rates (Exelon, PHI and Pepco).On June 30, 2016, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by $86 million, which was updated to $82 million on October 14, 2016, based on a requested ROE of 10.6%. The DCPSC has issued a procedural schedule indicating a final decision will be issued by July 25, 2017. Any adjustments to its rates approved by the DCPSC are expected to take effect soon thereafter. Pepco cannot predict how much of the requested increase the DCPSC will approve.
On April 18, 2016, a party to a separate DCPSC proceeding filed a motion to suspend Pepco’s bill stabilization adjustment (BSA), which decouples distribution revenues from utility customers from the amount of electricity delivered. On September 9, 2016, the DCPSC denied the party’s motion and determined that the appropriate forum in which to determine whether the BSA continues to be just and reasonable is in Pepco’s rate case proceeding. In addition, the DCPSC stated that it was putting Pepco on notice that all funds collected for the BSA from January 2015 to the issuance of a decision in the rate case proceeding are subject to refund should the
DCPSC determine that such funds were not justly or reasonably collected. On October 7, 2016, Pepco filed for reconsideration of this order and requested clarification that the order was not final and that the BSA matter would be decided in the base rate case. Pepco also argued that, if the order were considered final, the DCPSC reconsider its ruling that funds collected from the BSA can be retroactively refunded. Pepco cannot predict the outcome of this matter or the impact of a refund if ordered by the DCPSC.
2016 Electric Distribution Base Rates (Exelon, PHI and ACE). On August 24, 2016, the NJBPU issued an order approving a stipulation of settlement among ACE, the New Jersey Division of Rate Counsel, NJBPU Staff and Unimin Corporation, and an increase of $45 million (before New Jersey sales and use tax) to its electric distribution base rates, with the new rates effective immediately. The stipulation of settlement provided that a determination on PowerAhead would be separated into a phase II of the rate proceeding and decided at a later date and the parties would seek to resolve the matter by the end of 2016, although resolution will most likely occur in the first quarter of 2017. PowerAhead includes capital investments to advance modernization of the electric grid through energy efficiency, increased distributed generation, and resiliency, focused on improving the distribution system’s ability to withstand major storm events. ACE cannot predict if the NJBPU will approve the PowerAhead initiative.
Update and Reconciliation of Certain Under-Recovered Balances (Exelon, PHI and ACE).On February 1, 2016, ACE submitted its 2016 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollectible accounts.
The net impact of adjusting the charges as proposed is an overall annual rate increase of $9 million (revised to $19 million in April 2016, based upon an update for actuals through March 2016), including New Jersey sales and use tax. The matter is pending at the NJBPU.
Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE).The following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s electric transmission formula rate filings:
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Annual Transmission Filings(a) | ComEd | BGE | Pepco | DPL | ACE | |||||||||||||||
Initial revenue requirement increase | $ | 90 | $ | 12 | $ | 2 | $ | 8 | $ | 8 | ||||||||||
Annual reconciliation (decrease) increase | 4 | 3 | (10 | ) | (10 | ) | (14 | ) | ||||||||||||
Dedicated facilities (decrease) increase | 13 | |||||||||||||||||||
MAPP abandonment recovery decrease | — | — | (15 | ) | (12 | ) | — | |||||||||||||
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Total revenue requirement increase (decrease) | $ | 94 | $ | 28 | $ | (23 | ) | $ | (14 | ) | $ | (6 | ) | |||||||
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Allowed return on rate base(b) | 8.47 | % | 8.09 | % | 7.88 | % | 7.21 | % | 7.83 | % | ||||||||||
Previously authorized allowed return on rate base(b) | 8.61 | % | 8.46 | % | 8.36 | % | 7.80 | % | 8.51 | % | ||||||||||
Allowed ROE(c) | 11.50 | % | 10.50 | % | 10.50 | % | 10.50 | % | 10.50 | % |
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Conduit Lease with City of Baltimore (Exelon and BGE). On September 23, 2015, the Baltimore City Board of Estimates approved an increase in rental fees for access to the Baltimore City underground conduit
system effective November 1, 2015, which is expected to result in an increase to Operating and maintenance expense of approximately $25 million in 2016 subject to an annual increase based on the Consumer Price Index. On October 16, 2015, BGE filed a lawsuit against the City in the Circuit Court for Baltimore City to protect its customers from any improper use by the City of the conduit fee revenues and to place constraints on the City’s ability to set the conduit fee in the future.
Among the relief sought by BGE was a preliminary injunction preventing the City from enforcing its substantial increase in the conduit fee rate during the course of the litigation. A hearing was held in the Circuit Court for Baltimore City on December 15, 2015. While BGE’s motion for preliminary injunction was denied, the Court’s decision was premised upon several important concessions or acknowledgments made by the City in its written papers and at the hearing. Most importantly, the City conceded that it can charge BGE only for the actual costs of conduit maintenance and that a true-up process is required to the extent that the City fails to spend the amount collected for conduit maintenance. On July 12-13, 2016, the parties participated in non-binding mediation in an effort to resolve their disputes, but such mediation was unsuccessful. Due to concerns with the scheduling order entered by the Circuit Court, the parties stipulated to the dismissal of the lawsuit; however, BGE has the right to re-file the lawsuit. On August 25, 2016, BGE filed a motion to intervene in a lawsuit filed by several other tenants in the conduit system against the City in the United States District Court for the District of Maryland. BGE cannot predict the outcome of its motion for intervention or the accompanying complaint.
As part of its electric and gas distribution rate case filed on November 6, 2015, and as amended in the first quarter of 2016, BGE proposed to recover the annual increase in conduit fees effective November 1, 2015 of approximately $30 million through a surcharge. On June 3, 2016, the MDPSC issued a final order which did not allow BGE to recover or defer the $30 million in annual Baltimore City conduit fees. On June 30, 2016, BGE filed a petition for rehearing of the June 3 order requesting, among other things, that the MDPSC modify its decision to deny recovery of the Baltimore County conduit fees. On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that, among other things, denied BGE’s request that it be allowed to defer or recover through a surcharge the increase in Baltimore City underground conduit fees. On August 26, 2016, BGE filed an appeal of the MDPSC’s orders with the Circuit Court for Baltimore County. On August 29, 2016, the residential consumer advocate also filed an appeal of the MDPSC’s order but with the Circuit Court for Baltimore City. BGE cannot predict the outcome of these appeals.
Employees
During the second and third quarters of 2016, Exelon BSC and ComEd extended the collective bargaining agreement (CBA) with IBEW Local 15 by three years; with an expiration date of September 30, 2022. Exelon Generation extended its CBA with both the IBEW Local 15 (covering the five (5) Midwest nuclear plants) and IBEW Local 51 (Clinton) by three years; with expiration dates of April 30, 2022 and December 15, 2023, respectively. Additionally, Exelon Nuclear Security successfully ratified its CBA with the UGSOA Local 17 at Oyster Creek to an extension of five (5) years, and Exelon Power successfully ratified its CBA with the IBEW Local 614 to a three (3)year extension. In January 2017, an election was held at BGE which resulted in union representation for approximately 1,400 employees. BGE and IBEW Local 410 will begin negotiations for an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. No agreement has been finalized to date and management cannot predict the outcome of such negotiations. In April 2017, Exelon Nuclear Security successfully ratified its CBA with the SPFPA Local 238 at Quad Cities to an extension of three years.
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. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—OPERATIONS — CRITICAL ACCOUNTING POLICIES AND ESTIMATES in Exelon’s, Generation’s, ComEd’s, PECO’s, and BGE’s, combined 2015 Form 10-K and PHI’s,
Pepco’s, DPL’s and ACE’s 2015 combined 2016 Form10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, goodwill, purchase accounting, unamortized energy assets and liabilities, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies, revenue recognition, and allowance for uncollectible accounts. At September 30, 2016,March 31, 2017, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2015.2016.
Results of Operations By Business Segment
Net Income (Loss) Attributable to Common Shareholders by Registrant
Three Months Ended September 30, | Favorable (Unfavorable) Variance | Nine Months Ended September 30, | Favorable (Unfavorable) Variance | Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||||||||||||||
2016 | 2015 | 2016(a) | 2015 | 2017 | 2016(a) | |||||||||||||||||||||||||||||||
Exelon | $ | 490 | $ | 629 | $ | (139 | ) | $ | 930 | $ | 1,959 | $ | (1,029 | ) | $ | 995 | $ | 173 | $ | 822 | ||||||||||||||||
Generation | 236 | 377 | (141 | ) | 538 | 1,218 | (680 | ) | 423 | 310 | 113 | |||||||||||||||||||||||||
ComEd | 37 | 149 | (112 | ) | 297 | 339 | (42 | ) | 141 | 115 | 26 | |||||||||||||||||||||||||
PECO | 122 | 90 | 32 | 346 | 299 | 47 | 127 | 124 | 3 | |||||||||||||||||||||||||||
BGE | 54 | 51 | 3 | 183 | 202 | (19 | ) | 125 | 98 | 27 | ||||||||||||||||||||||||||
Pepco | 79 | 60 | 19 | 20 | 128 | (108 | ) | 58 | (108 | ) | 166 | |||||||||||||||||||||||||
DPL | 44 | 15 | 29 | (16 | ) | 55 | (71 | ) | 57 | (72 | ) | 129 | ||||||||||||||||||||||||
ACE | 47 | 22 | 25 | (50 | ) | 37 | (87 | ) | 28 | (100 | ) | 128 |
(a) | For Pepco, DPL and ACE, reflects that Registrant’s operations for the |
Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | March 24 to September 30, | January 1 to March 23, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2016 | 2015 | ||||||||||||||||||||||||||||||||
PHI | $ | 166 | $ | 91 | $ | (91 | ) | $ | 19 | $ | 197 |
PHI Successor Predecessor Three
Months
Ended
March 31,
2017 March 24,
2016 to
March 31,
2016 January 1,
2016 to
March 23,
2016 $ 140 $ (309 ) $ 19
Results of Operations — Generation
Three Months Ended September 30, | Favorable (Unfavorable) Variance | Nine Months Ended September 30, | Favorable (Unfavorable) Variance | Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||||||||||||
Operating revenues | $ | 5,035 | $ | 4,768 | $ | 267 | $ | 13,363 | $ | 14,841 | $ | (1,478 | ) | $ | 4,888 | $ | 4,739 | $ | 149 | |||||||||||||||||
Purchased power and fuel expense | 2,589 | 2,519 | (70 | ) | 6,609 | 7,800 | 1,191 | 2,798 | 2,442 | (356 | ) | |||||||||||||||||||||||||
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Revenue net of purchased power and fuel(a) | 2,446 | 2,249 | 197 | 6,754 | 7,041 | (287 | ) | |||||||||||||||||||||||||||||
Revenues net of purchased power and fuel expense(a) | 2,090 | 2,297 | (207 | ) | ||||||||||||||||||||||||||||||||
Other operating expenses | ||||||||||||||||||||||||||||||||||||
Operating and maintenance | 1,336 | 1,241 | (95 | ) | 4,333 | 3,860 | (473 | ) | 1,488 | 1,467 | (21 | ) | ||||||||||||||||||||||||
Depreciation and amortization | 632 | 264 | (368 | ) | 1,329 | 774 | (555 | ) | 302 | 289 | (13 | ) | ||||||||||||||||||||||||
Taxes other than income | 136 | 123 | (13 | ) | 380 | 369 | (11 | ) | 143 | 126 | (17 | ) | ||||||||||||||||||||||||
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Total other operating expenses | 2,104 | 1,628 | (476 | ) | 6,042 | 5,003 | (1,039 | ) | 1,933 | 1,882 | (51 | ) | ||||||||||||||||||||||||
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Gain on sales of assets | — | 1 | (1 | ) | 31 | 7 | 24 | 4 | — | 4 | ||||||||||||||||||||||||||
Bargain purchase gain | 226 | — | 226 | |||||||||||||||||||||||||||||||||
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Operating income | 342 | 622 | (280 | ) | 743 | 2,045 | (1,302 | ) | 387 | 415 | (28 | ) | ||||||||||||||||||||||||
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Other income and (deductions) | ||||||||||||||||||||||||||||||||||||
Interest expense, net | (77 | ) | (68 | ) | (9 | ) | (273 | ) | (269 | ) | (4 | ) | (100 | ) | (97 | ) | (3 | ) | ||||||||||||||||||
Other, net | 185 | (257 | ) | 442 | 395 | (193 | ) | 588 | 259 | 93 | 166 | |||||||||||||||||||||||||
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Total other income and (deductions) | 108 | (325 | ) | 433 | 122 | (462 | ) | 584 | 159 | (4 | ) | 163 | ||||||||||||||||||||||||
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Income before income taxes | 450 | 297 | 153 | 865 | 1,583 | (718 | ) | |||||||||||||||||||||||||||||
Income taxes | 173 | (36 | ) | (209 | ) | 293 | 371 | 78 | ||||||||||||||||||||||||||||
Equity in losses of unconsolidated affiliates | (6 | ) | (1 | ) | (5 | ) | (16 | ) | (4 | ) | (12 | ) | ||||||||||||||||||||||||
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Net income | 271 | 332 | (61 | ) | 556 | 1,208 | (652 | ) | ||||||||||||||||||||||||||||
Net income (loss) attributable to noncontrolling interests | 35 | (45 | ) | (80 | ) | 18 | (10 | ) | (28 | ) | ||||||||||||||||||||||||||
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Net income attributable to membership interest | $ | 236 | $ | 377 | $ | (141 | ) | $ | 538 | $ | 1,218 | $ | (680 | ) | ||||||||||||||||||||||
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Income before income taxes Income taxes Equity in losses of unconsolidated affiliates Net income Net loss attributable to noncontrolling interests Net income attributable to membership interest Three Months Ended
March 31, Favorable
(Unfavorable)
Variance 2017 2016 546 411 135 127 151 24 (10 ) (3 ) (7 ) 409 257 152 (14 ) (53 ) (39 ) $ 423 $ 310 $ 113
(a) | Generation evaluates its operating performance using the measure of revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue net of purchased power and fuel expense 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. |
Net Income Attributable to Membership Interest
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015. March 31, 2016.Generation’s net income attributable to membership interest for the three months ended September 30, 2016 decreasedMarch 31, 2017 increased compared to the same period in 2015,2016, primarily due to higher operatinga bargain purchase gain associated with the acquisition of FitzPatrick, increased other income, and maintenance expense, higher depreciation and amortization expense and increasedlower income tax expense,taxes, partially offset by higherlower revenue net of purchased power and fuel expense, and increased other income. The increase inhigher operating and maintenance expense is primarily related to impairment of Upstream assets and increased costs related to the cost management program. The increase inhigher depreciation and amortization expense is primarily related. The bargain purchase gain relates to accelerated depreciationthe excess of the fair value of assets and amortization expenseliabilities acquired over the purchase price related to the decision to early retire the Clinton and Quad Cities nuclear generating facilities, increased nuclear decommissioning amortization and increased depreciation expense due to ongoing capital expenditures. The increase in income taxes given a decrease in the domestic production activities
deduction and absence of favorable settlement of certain income tax positions at Constellation in 2015. The increase in revenue net of purchased power and fuel expense primarily relates to higher mark-to-market results in 2016 compared to 2015 and the Ginna Reliability Support Services Agreement partially offset by decreased capacity prices and lower realized energy prices.FitzPatrick acquisition. The increase in other income is primarily due to the change in realized and unrealized gains and losses on NDT funds.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. Generation’s net income attributable to membership interest for the nine months ended September 30, 2016 decreased compared to the same period in 2015, primarily due to lower revenue net of purchased power and fuel expense, higher operating and maintenance expense and higher depreciation and amortization expense, partially offset by increased other income. The decrease in revenuerevenues net of purchased power and fuel expense primarily relates to lower mark-to-market results losses in 2017 compared tomark-to-market gains in 2016, compared to 2015,the impacts of declining natural gas prices on Generation’s natural gas portfolio, decreased capacity prices and lower realized energy prices, and increased oil inventory write-downs, partially offset by the impact of the Ginna Reliability Support Services Agreement decreased fuel prices and a decreasethe absence of oil inventory write downs in outage days at higher capacity units despite an increase in overall outage days.2017. The increase in operating and maintenance expense is primarily related to the decision to early retire the Clinton and Quad Cities nuclear generating facilities, impairment of Upstream assets and certain wind projects and increased costs related to the cost management program. Thean increase in depreciation and amortization expense is primarily related to accelerated depreciation and amortization expense related to the decision to early retire the Clinton and Quad Citiesnumber of nuclear generating facilities, increased nuclear decommissioning amortization and increased depreciation expense due to ongoing capital expenditures. The increaseoutage days in other income is primarily due to the change in realized and unrealized gains and losses on NDT funds.2017.
RevenueRevenues 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. Descriptions of each of Generation’s six reportable segments are as follows:
• | Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina. |
• | Midwest represents operations in the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky. |
• | New England represents the operations withinISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. |
• | New York represents operations withinISO-NY, which covers the state of New York in its entirety. |
• | ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas. |
• | Other Power Regions: |
• | South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas. |
• | West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota. |
• | Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO. |
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 Generation’s overall operating revenues or results of operations. Further, the following activities are not allocated to a region, and are reported in Other: amortization of certain intangible assets relating to commodity contracts recorded at fair value from mergers and acquisitions; accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.
Generation evaluates the operating performance of its power marketingelectric business activities using the measure of revenue net of purchased power and fuel expense, which is anon-GAAP measurement. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.
For the three and nine months ended September 30,March 31, 2017 and 2016, and 2015, Generation’s revenue net of purchased power and fuel expense by region were as follows:
Three Months Ended September 30, | Variance | % Change | Nine Months Ended September 30, | Variance | % Change | Three Months Ended March 31, | Variance | % Change | ||||||||||||||||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||||||||||||||||||||||||
Mid-Atlantic(a) | $ | 887 | $ | 997 | $ | (110 | ) | (11.0 | )% | $ | 2,556 | $ | 2,677 | $ | (121 | ) | (4.5 | )% | $ | 773 | $ | 841 | $ | (68 | ) | (8.1 | )% | |||||||||||||||||||||
Midwest(b) | 781 | 756 | 25 | 3.3 | % | 2,229 | 2,205 | 24 | 1.1 | % | 715 | 718 | (3 | ) | (0.4 | )% | ||||||||||||||||||||||||||||||||
New England | 160 | 133 | 27 | 20.3 | % | 350 | 379 | (29 | ) | (7.7 | )% | 111 | 81 | 30 | 37.0 | % | ||||||||||||||||||||||||||||||||
New York | 194 | 170 | 24 | 14.1 | % | 592 | 502 | 90 | 17.9 | % | 153 | 130 | 23 | 17.7 | % | |||||||||||||||||||||||||||||||||
ERCOT | 93 | 111 | (18 | ) | (16.2 | )% | 231 | 235 | (4 | ) | (1.7 | )% | 69 | 61 | 8 | 13.1 | % | |||||||||||||||||||||||||||||||
Other Power Regions | 77 | 83 | (6 | ) | (7.2 | )% | 253 | 193 | 60 | 31.1 | % | 64 | 76 | (12 | ) | (15.8 | )% | |||||||||||||||||||||||||||||||
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Total electric revenue net of purchased power and fuel expense | 2,192 | 2,250 | (58 | ) | (2.6 | )% | 6,211 | 6,191 | 20 | 0.3 | % | 1,885 | 1,907 | (22 | ) | (1.2 | )% | |||||||||||||||||||||||||||||||
Proprietary Trading | 3 | — | 3 | n.m. | 9 | 3 | 6 | 200.0 | % | — | 3 | (3 | ) | (100.0 | )% | |||||||||||||||||||||||||||||||||
Mark-to-market gains / (losses) | 88 | (139 | ) | 227 | (163.3 | )% | (113 | ) | 258 | (371 | ) | (143.8 | )% | |||||||||||||||||||||||||||||||||||
Mark-to-market (losses) gains | (49 | ) | 103 | (152 | ) | (147.6 | )% | |||||||||||||||||||||||||||||||||||||||||
Other(c) | 163 | 138 | 25 | 18.1 | % | 647 | 589 | 58 | 9.8 | % | 254 | 284 | (30 | ) | (10.6 | )% | ||||||||||||||||||||||||||||||||
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Total revenue net of purchased power and fuel expense | $ | 2,446 | $ | 2,249 | $ | 197 | 8.8 | % | $ | 6,754 | $ | 7,041 | $ | (287 | ) | (4.1 | )% | $ | 2,090 | $ | 2,297 | $ | (207 | ) | (9.0 | )% | ||||||||||||||||||||||
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(a) | Results of transactions with PECO and BGE are included in theMid-Atlantic region. Results of transactions with Pepco, DPL, and ACE are included in theMid-Atlantic region |
(b) | Results of transactions with ComEd are included in the Midwest region. |
(c) | Other represents activities not allocated to a region. See text above for a description of included activities. Includes amortization of intangible assets related to commodity contracts recorded at fair value of a |
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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 March 31, | Variance | % Change | ||||||||||||||||||||||||||||||||||||||||
Supply source (GWh) | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||
Nuclear generation | ||||||||||||||||||||||||||||||||||||||||||||||||
Mid-Atlantic(a) | 15,604 | 16,446 | (842 | ) | (5.1 | )% | 47,035 | 47,783 | (748 | ) | (1.6 | )% | 16,545 | 16,208 | 337 | 2.1 | % | |||||||||||||||||||||||||||||||
Midwest | 24,262 | 23,927 | 335 | 1.4 | % | 70,925 | 69,802 | 1,123 | 1.6 | % | ||||||||||||||||||||||||||||||||||||||
Midwest(a) | 22,468 | 23,662 | (1,194 | ) | (5.0 | )% | ||||||||||||||||||||||||||||||||||||||||||
New York(a) | 4,843 | 4,807 | 36 | 0.7 | % | 14,002 | 14,057 | (55 | ) | (0.4 | )% | 4,491 | 4,932 | (441 | ) | (8.9 | )% | |||||||||||||||||||||||||||||||
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Total Nuclear Generation | 44,709 | 45,180 | (471 | ) | (1.0 | )% | 131,962 | 131,642 | 320 | 0.2 | % | 43,504 | 44,802 | (1,298 | ) | (2.9 | )% | |||||||||||||||||||||||||||||||
Fossil and Renewables | ||||||||||||||||||||||||||||||||||||||||||||||||
Mid-Atlantic | 706 | 719 | (13 | ) | (1.8 | )% | 2,290 | 2,028 | 262 | 12.9 | % | 836 | 898 | (62 | ) | (6.9 | )% | |||||||||||||||||||||||||||||||
Midwest | 273 | 262 | 11 | 4.2 | % | 1,046 | 1,057 | (11 | ) | (1.0 | )% | 418 | 449 | (31 | ) | (6.9 | )% | |||||||||||||||||||||||||||||||
New England | 1,886 | 1,840 | 46 | n.m. | 5,826 | 2,575 | 3,251 | n.m. | 2,077 | 1,924 | 153 | 8.0 | % | |||||||||||||||||||||||||||||||||||
New York | 1 | 1 | — | — | % | 3 | 3 | — | — | % | 1 | 1 | — | — | % | |||||||||||||||||||||||||||||||||
ERCOT | 2,472 | 2,306 | 166 | 7.2 | % | 5,726 | 4,600 | 1,126 | 24.5 | % | 1,370 | 1,376 | (6 | ) | (0.4 | )% | ||||||||||||||||||||||||||||||||
Other Power Regions | 2,103 | 1,945 | 158 | 8.1 | % | 6,245 | 6,014 | 231 | 3.8 | % | 1,423 | 2,147 | (724 | ) | (33.7 | )% | ||||||||||||||||||||||||||||||||
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Total Fossil and Renewables | 7,441 | 7,073 | 368 | 5.2 | % | 21,136 | 16,277 | 4,859 | 29.9 | % | 6,125 | 6,795 | (670 | ) | (9.9 | )% | ||||||||||||||||||||||||||||||||
Purchased Power | ||||||||||||||||||||||||||||||||||||||||||||||||
Mid-Atlantic | 7,139 | 3,511 | 3,628 | 103.3 | % | 14,024 | 6,719 | 7,305 | 108.7 | % | 3,398 | 3,755 | (357 | ) | (9.5 | )% | ||||||||||||||||||||||||||||||||
Midwest | 461 | 515 | (54 | ) | (10.5 | )% | 1,855 | 1,511 | 344 | 22.8 | % | 388 | 706 | (318 | ) | (45.0 | )% | |||||||||||||||||||||||||||||||
New England | 3,927 | 5,787 | (1,860 | ) | (32.1 | )% | 11,863 | 17,937 | (6,074 | ) | (33.9 | )% | 5,064 | 4,155 | 909 | 21.9 | % | |||||||||||||||||||||||||||||||
New York(b) | 28 | — | 28 | N/A | ||||||||||||||||||||||||||||||||||||||||||||
ERCOT | 2,895 | 2,422 | 473 | 19.5 | % | 7,448 | 7,569 | (121 | ) | (1.6 | )% | 2,655 | 2,294 | 361 | 15.7 | % | ||||||||||||||||||||||||||||||||
Other Power Regions | 3,803 | 5,812 | (2,009 | ) | (34.6 | )% | 10,281 | 14,186 | (3,905 | ) | (27.5 | )% | 2,384 | 2,600 | (216 | ) | (8.3 | )% | ||||||||||||||||||||||||||||||
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Total Purchased Power | 18,225 | 18,047 | 178 | 1.0 | % | 45,471 | 47,922 | (2,451 | ) | (5.1 | )% | 13,917 | 13,510 | 407 | 3.0 | % | ||||||||||||||||||||||||||||||||
Total Supply/Sales by Region(b) | ||||||||||||||||||||||||||||||||||||||||||||||||
Mid-Atlantic(c) | 23,449 | 20,676 | 2,773 | 13.4 | % | 63,349 | 56,530 | 6,819 | 12.1 | % | 20,779 | 20,861 | (82 | ) | (0.4 | )% | ||||||||||||||||||||||||||||||||
Midwest(c) | 24,996 | 24,704 | 292 | 1.2 | % | 73,826 | 72,370 | 1,456 | 2.0 | % | 23,274 | 24,817 | (1,543 | ) | (6.2 | )% | ||||||||||||||||||||||||||||||||
New England | 5,813 | 7,627 | (1,814 | ) | (23.8 | )% | 17,689 | 20,512 | (2,823 | ) | (13.8 | )% | 7,141 | 6,079 | 1,062 | 17.5 | % | |||||||||||||||||||||||||||||||
New York | 4,844 | 4,808 | 36 | 0.7 | % | 14,005 | 14,060 | (55 | ) | (0.4 | )% | 4,520 | 4,933 | (413 | ) | (8.4 | )% | |||||||||||||||||||||||||||||||
ERCOT | 5,367 | 4,728 | 639 | 13.5 | % | 13,174 | 12,169 | 1,005 | 8.3 | % | 4,025 | 3,670 | 355 | 9.7 | % | |||||||||||||||||||||||||||||||||
Other Power Regions | 5,906 | 7,757 | (1,851 | ) | (23.9 | )% | 16,526 | 20,199 | (3,673 | ) | (18.2 | )% | 3,807 | 4,747 | (940 | ) | (19.8 | )% | ||||||||||||||||||||||||||||||
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Total Supply/Sales by Region | 70,375 | 70,300 | 75 | 0.1 | % | 198,569 | 195,840 | 2,729 | 1.4 | % | 63,546 | 65,107 | (1,561 | ) | (2.4 | )% | ||||||||||||||||||||||||||||||||
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(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) | Excludes physical proprietary trading volumes of |
(c) | Includes affiliate sales to PECO and BGE in theMid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the PHI Merger, includes affiliate sales to Pepco, DPL and ACE in theMid-Atlantic region |
Mid-Atlantic
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015. March 31, 2016.The $110$68 million decrease in revenue net of purchased power and fuel expense in theMid-Atlantic primarily reflects decreased capacity prices, lower realized energy prices and increased nuclear outage days.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. The $121 million decrease in revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower realized energy prices and decreased capacity prices, and higherpartially offset by the absence of oil inventory write-downs in 2016, partially offset by increased load volumes served.2017.
Midwest
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015. March 31, 2016.The $25$3 million increasedecrease in revenue net of purchased power and fuel expense in the Midwest primarily reflects decreasedincreased nuclear outage days and decreased capacity prices, partially offset by decreased nuclear fuel prices and higher realized energy prices.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. The $24 million increase in revenue net of purchased power and fuel expense in the Midwest primarily reflects decreased nuclear outage days and increased capacity prices, partially offset by lower realized energy prices.
New England
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.March 31, 2016. The $27$30 million increase in revenue net of purchased power and fuel expense in New England was driven by increased capacity prices.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. The $29 million decrease in revenue netthe absence of purchased power and fuel expense in New England was driven by lower realized energy prices and higher oil inventory write-downs in 2016, partially offset by2017 and increased capacity prices.
New York
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015. March 31, 2016.The $24$23 million increase in revenue net of purchased power and fuel expense in New York was primarily due to the impact of the Ginna Reliability Support Service Agreement.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. The $90 million increase in revenue net of purchased power and fuel expense in New York was primarily due to the approval of the Ginna Reliability Support Service Agreement, partially offset by lower realized energy prices.increased nuclear outage days.
ERCOT
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015. March 31, 2016.The $18$8 million decreaseincrease in revenue net of purchased power and fuel expense in ERCOT was primarily due to lowerhigher realized energy prices.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. The $4 million decrease in revenue net of purchased power and fuel expense in ERCOT was primarily due to lower realized energy prices, partially offset by increased output from renewable assets.
Other Power Regions
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.March 31, 2016. The $6$12 million decrease in revenue net of purchased power and fuel expense in Other Power Regions was primarily due to lower realized energy prices.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. The $60 million increase in revenue net of purchased power and fuel expense in Other Power Regions was primarily due to higher realized energy prices.
Proprietary Trading
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.March 31, 2016. The $3 million increasedecrease in revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. The $6 million increase in revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.Mark-to-market
Mark-to-market
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.March 31, 2016. Mark-to-market gains losses on economic hedging activities were $88$49 million for the three months ended September 30, 2016March 31, 2017 compared to lossesgains of $139$103 million for the three months ended September 30, 2015March 31, 2016. See Notes 8 — 8—Fair Value of Financial Assets and Liabilities and 9 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated withmark-to-market derivatives.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015.Mark-to-market losses on economic hedging activities were $113 million for the nine months ended September 30, 2016 compared to gains of $258 million for the nine months ended September 30, 2015. See Notes 8 — Fair Value of Financial Assets and Liabilities and 9 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.
Other
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.March 31, 2016. The $25$30 million increasedecrease in other revenue net of purchased power and fuel was primarily due to revenue related to the inclusionimpacts of Pepco Energy Services results in 2016declining natural
gas prices on Generation’s natural gas portfolio and revenue related to energy efficiency projects, partially offset by the amortization of energy contracts recorded at fair value associated with prior acquisitions, and accelerated nuclear fuel amortization associated with nuclear decommissioning as discussed in Note 7 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. The $58 million increase in other revenue net of purchased power and fuel was primarily due topartially offset by revenue related to the inclusion of Pepco Energy Services results in 20162017 and revenue related to energy efficiency projects, partially offset by the amortization of energy contracts recorded at fair value associated with prior acquisitions, and accelerated nuclear fuel amortization associated with nuclear decommissioning as discussed in Note 7 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements.
Nuclear Fleet Capacity Factor
The following table presents nuclear fleet operating data for the three and nine months ended September 30, 2016March 31, 2017 as compared to the same periodsperiod in 2015,2016, for the Generation-operated plants. 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, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Nuclear fleet capacity factor(a) | 96.3 | % | 95.5 | % | 94.8 | % | 93.8 | % |
Three Months Ended March 31, | ||||||||
2017 | 2016 | |||||||
Nuclear fleet capacity factor(a) | 94.0 | % | 95.8 | % |
(a) | Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage of stations operated by Exelon. |
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.March 31, 2016. The nuclear fleet capacity factor increaseddecreased primarily due to fewermore refueling and non-refueling outage days, excluding Salem outages, during the three months ended September 30, 2016March 31, 2017 compared to the same period in 2015.2016. For the three months ended September 30,March 31, 2017 and 2016, and 2015, planned refueling outage days totaled 1795 and 27, respectively. During the same periods, 70, respectively, andnon-refueling outage days totaled zero8 and 11,10, respectively.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. The nuclear fleet capacity factor increased primarily due to fewer refueling and non-refueling outage days, excluding Salem outages, during the nine months ended September 30, 2016 compared to the same period in 2015. For the nine months ended September 30, 2016 and 2015, planned refueling outage days totaled 174 and 187, respectively. During the same periods, non-refueling outage days totaled 31 and 61, respectively.
Operating and Maintenance
The changes in operating and maintenance expense for the three and nine months ended September 30, 2016March 31, 2017 as compared to the same periodsperiod in 2015,2016, consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Labor, other benefits, contracting, materials | $ | 106 | $ | 144 | ||||
Nuclear refueling outage costs, including the co-owned Salem plants(a) | (8 | ) | 10 | |||||
Corporate allocations(b) | 24 | 12 | ||||||
Merger and integration costs | 5 | 5 | ||||||
Merger commitments | — | 3 | ||||||
Plant retirements and divestitures(c) | (36 | ) | 91 | |||||
Impairment of long-lived assets(d) | 15 | 171 | ||||||
Cost management program(e) | 11 | 35 | ||||||
Midwest Generation bankruptcy recoveries(f) | — | 10 | ||||||
Asset retirement obligation update(g) | 10 | 10 | ||||||
Pension and non-pension postretirement benefits expense(h) | (11 | ) | (35 | ) | ||||
Accretion expense | (11 | ) | (10 | ) | ||||
Other | (10 | ) | 27 | |||||
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Increase in operating and maintenance expense | $ | 95 | $ | 473 | ||||
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Labor, other benefits, contracting, materials(a) Nuclear refueling outage costs, including theco-owned Salem plants(b) Corporate allocations Merger and integration costs(c) Merger commitments Cost management program(d) Long-Lived Asset Impairments(e) Pension andnon-pension postretirement benefits expense Allowance for uncollectible accounts Accretion expense Other Increase in operating and maintenance expense Three Months Ended
March 31, Increase (Decrease) $ 80 28 4 27 (3 ) (14 ) (109 ) (3 ) 3 6 2 $ 21
(a) | Primarily reflects the |
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Depreciation and Amortization
Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016. Depreciation and amortization expense for the three and nine months ended September 30, 2016 compared to the three and nine months ended September 30, 2015 increased primarily due to accelerated depreciation related to the decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, increased nuclear decommissioning amortization and increased depreciation expense due to ongoing capital expenditures.
Taxes Other Than Income
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.March 31, 2016. Taxes other than income taxes, which can vary period to period, includenon-income municipal and state utility taxes, real estate taxes and payroll taxes. The increase primarily relates to property and gross receipts tax.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. Taxes other than income taxes, which can vary period to period, include non-income municipal and state utility taxes, real estate taxes and payroll taxes. The increase primarily relates to gross receipts and sales and use tax.
Gain on Sales of Assets
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.March 31, 2016. Gain on sales of assets for the three months ended September 30, 2016 compared to the three months ended September 30, 2015 remained relatively stable.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. Gain on sales of assets for the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015 increased primarily as a result of the gain associated with Generation’s sale of Conectiv Thermal Systems.
Bargain Purchase Gain
Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016. Bargain purchase gain increased as a result of the New Boston generating site.gain associated with Generation’s Fitzpatrick acquisition. Refer to Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.
Interest Expense, net
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.March The increase in interest expense for the three months ended September 30, 2016 compared to the three months ended September 30, 2015 is primarily due to higher outstanding debt.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. 31, 2016. Interest expense for the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015 remained relatively stable.
Other, Net
Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016. Other, net for the three and nine months ended September 30, 2016 compared to the three and nine months ended September 30, 2015 increased primarily due to the change in the realized and unrealized gains and losses related to NDT funds ofNon-Regulatory Agreement Units as described in the table below. Other, net also reflects $39$56 million and $(55)$20 million for the three months ended September 30,March 31, 2017 and 2016, and 2015, respectively, and $84 million and $(44) million for the nine months ended September 30, 2016 and 2015, respectively, related to the contractual elimination of income tax expense (benefit) associated with the NDT funds of the Regulatory Agreement Units. Refer to Note 12 — Nuclear Decommissioning of the Combined Notes to the Consolidated Financial Statements for additional information regarding NDT funds.
The following table provides unrealized and realized gains and losses on the NDT funds of theNon-Regulatory Agreement Units recognized in Other, net for the three and nine months ended September 30, 2016March 31, 2017 and 2015:2016:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Net unrealized gains (losses) on decommissioning trust funds | $ | 116 | $ | (218 | ) | $ | 216 | $ | (274 | ) | ||||||
Net realized gains (losses) on sale of decommissioning trust funds | 12 | (3 | ) | 26 | 53 |
Three Months Ended March 31, | ||||||||
2017 | 2016 | |||||||
Net unrealized gains on decommissioning trust funds | $ | 166 | $ | 52 | ||||
Net realized gains on sale of decommissioning trust funds | 9 | 3 |
Equity in Losses of Unconsolidated Affiliates
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.MarchEquity in losses of unconsolidated affiliates for the three months ended September 30, 2016 compared to the three months ended September 30, 2015 remained relatively stable.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. 31, 2016.The increase in equity in losses of unconsolidated affiliates for the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015 increased as a result of losses on equity investments.
Effective Income Tax Rate
Generation’s effective income tax rate was 38.4%23.3% and 33.9%36.7% for the three and nine months ended September 30,March 31, 2017 and 2016, respectively, compared to (12.1)% and 23.4% for the same periods during 2015.respectively. See Note 11 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
Three Months Ended September 30, | Favorable (Unfavorable) Variance | Nine Months Ended September 30, | Favorable (Unfavorable) Variance | Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||||||||||||
Operating revenues | $ | 1,497 | $ | 1,376 | $ | 121 | $ | 4,031 | $ | 3,709 | $ | 322 | $ | 1,298 | $ | 1,249 | $ | 49 | ||||||||||||||||||
Purchased power expense | 454 | 390 | (64 | ) | 1,141 | 991 | (150 | ) | 334 | 348 | 14 | |||||||||||||||||||||||||
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Revenue net of purchased power expense(a)(b) | 1,043 | 986 | 57 | 2,890 | 2,718 | 172 | ||||||||||||||||||||||||||||||
Revenues net of purchased power expense(a)(b) | 964 | 901 | 63 | |||||||||||||||||||||||||||||||||
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Other operating expenses | ||||||||||||||||||||||||||||||||||||
Operating and maintenance | 377 | 404 | 27 | 1,113 | 1,166 | 53 | 370 | 368 | (2 | ) | ||||||||||||||||||||||||||
Depreciation and amortization | 196 | 176 | (20 | ) | �� | 574 | 528 | (46 | ) | 208 | 189 | (19 | ) | |||||||||||||||||||||||
Taxes other than income | 82 | 79 | (3 | ) | 222 | 225 | 3 | 72 | 75 | 3 | ||||||||||||||||||||||||||
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Total other operating expenses | 655 | 659 | 4 | 1,909 | 1,919 | 10 | 650 | 632 | (18 | ) | ||||||||||||||||||||||||||
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Gain on sales of assets | 1 | — | 1 | 6 | — | 6 | — | 5 | (5 | ) | ||||||||||||||||||||||||||
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Operating income | 389 | 327 | 62 | 987 | 799 | 188 | 314 | 274 | 40 | |||||||||||||||||||||||||||
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Other income and (deductions) | ||||||||||||||||||||||||||||||||||||
Interest expense, net | (197 | ) | (83 | ) | (114 | ) | (374 | ) | (248 | ) | (126 | ) | (85 | ) | (86 | ) | 1 | |||||||||||||||||||
Other, net | (80 | ) | 4 | (84 | ) | (72 | ) | 14 | (86 | ) | 4 | 4 | — | |||||||||||||||||||||||
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Total other income and (deductions) | (277 | ) | (79 | ) | (198 | ) | (446 | ) | (234 | ) | (212 | ) | (81 | ) | (82 | ) | 1 | |||||||||||||||||||
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Income before income taxes | 112 | 248 | (136 | ) | 541 | 565 | (24 | ) | 233 | 192 | 41 | |||||||||||||||||||||||||
Income taxes | 75 | 99 | 24 | 244 | 226 | (18 | ) | 92 | 77 | (15 | ) | |||||||||||||||||||||||||
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Net income | $ | 37 | $ | 149 | $ | (112 | ) | $ | 297 | $ | 339 | $ | (42 | ) | $ | 141 | $ | 115 | $ | 26 | ||||||||||||||||
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(a) | ComEd evaluates its operating performance using the measure of Revenue net of purchased power expense. ComEd believes that Revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included its discussion of Revenue net of purchased power expense below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense 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. |
(b) | For regulatory recovery mechanisms, including ComEd’s electric distribution and transmission formula rates, and riders, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings). |
Net Income
Three Months Ended September 30, 2016months ended March 31, 2017 Compared to Three months ended September 30, 2015.March 31, 2016. ComEd’s Net income for the three months ended September 30, 2016March 31, 2017 was lowerhigher than the same period in 2015,2016, primarily due to the recognition of the penalty and the after-tax interest due on the asserted penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position, partially offset by increased electric distribution and transmission formula rate earnings (reflecting the impactseffects of increased capital investment partially offset by lowerand higher allowed electric distribution ROE) and favorable weather.
Nine months ended September 30, 2016 Compared to Nine months ended September 30, 2015. ComEd’s Net income for the nine months ended September 30, 2016 was lower than the same period in 2015, primarily due to the recognition of the penalty and the after-tax interest due on the asserted penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position, partially offset by increased electric distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment, partially offset by lower allowed electric distribution ROE) and favorable weather..
Operating RevenueRevenues Net of Purchased Power Expense
There are certain drivers of Operating revenuerevenues that are fully offset by their impact on Purchased power expense, such as commodity procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity procurement costs from retail customers withoutmark-up. Therefore, fluctuations in electricity procurement costs have no impact on Revenue net of purchased power expense. See Note 3 — Regulatory Matters of the Exelon 20152016 Form10-K for additional information on ComEd’s electricity procurement process.
All ComEd customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact ComEd’s volume of deliveries, but do affect ComEd’s Operating revenuerevenues related to supplied energy, which is fully offset in Purchased power expense. Therefore, customer choice programs have no impact on Revenue net of purchased power expense.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and nine months ended September 30,March 31, 2017 and 2016, and 2015, consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
70 | % | 75 | % | 72 | % | 77 | % |
Three Months Ended March 31, | ||||||||
2017 | 2016 | |||||||
Electric | 71 | % | 73 | % |
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30,March 31, 2017 and 2016 and 2015 consisted of the following:
September 30, 2016 | September 30, 2015 | |||||||||||||||
Number of customers | % of total retail customers | Number of customers | % of total retail customers | |||||||||||||
1,526,900 | 39 | % | 1,664,600 | 43 | % |
Under an Illinois law allowing municipalities to arrange the purchase of electricity for their participating residents, the City of Chicago previously participated in ComEd’s customer choice program and arranged the purchase of electricity from Constellation (formerly Integrys), for those participating residents. In September 2015, the City of Chicago discontinued its participation in the customer choice program and many of those participating residents resumed their purchase of electricity from ComEd. ComEd’s Operating revenue has increased as a result of the City of Chicago switching, but that increase is fully offset in Purchased power expense.
March 31, 2017 | March 31, 2016 | |||||||||||||||
Number of customers | % of total retail customers | Number of customers | % of total retail customers | |||||||||||||
1,453,000 | 36 | % | 1,649,700 | 42 | % |
The changes in ComEd’s Revenue net of purchased power expense for the three and nine months ended September 30, 2016,March 31, 2017, compared to the same periodsperiod in 20152016 consisted of the following:
Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | Three Months Ended March 31, 2017 | ||||||||||
Increase (Decrease) | Increase (Decrease) | Increase (Decrease) | ||||||||||
Weather | $ | 38 | $ | 41 | $ | 8 | ||||||
Volume | 5 | 2 | (1 | ) | ||||||||
Electric distribution revenue | 20 | 86 | 24 | |||||||||
Transmission revenue | 19 | 87 | 17 | |||||||||
Regulatory required programs | (25 | ) | (41 | ) | 20 | |||||||
Uncollectible accounts recovery, net | 2 | (15 | ) | (2 | ) | |||||||
Pricing and customer mix | (11 | ) | (5 | ) | (3 | ) | ||||||
Other | 9 | 17 | ||||||||||
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Total increase | $ | 57 | $ | 172 | $ | 63 | ||||||
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(a) | These changes only reflect the 2016 impacts of weather, volume, and pricing and customer mix. As further described below, pursuant to the revenue decoupling provision in FEJA, ComEd began recording an adjustment to revenue in the first quarter of 2017 to eliminate the favorable or unfavorable impacts associated with variations in delivery volumes associated with above or below normal weather, number of customers or usage per customer. |
Weather. Revenue Decoupling.The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased customer usage. Conversely, mild weather reduces demand. For
Under EIMA, ComEd’s electric distribution formula rate provided for an adjustment to future billings if its earned ROE fell outside a 50 bps collar of its allowed ROE, which partially eliminated the threeimpacts of weather and nine months ended September 30, 2016,load on ComEd’s revenue. As allowed under FEJA, ComEd will revise its electric distribution formula rate to eliminate the ROE collar beginning with the reconciliation filed in 2018 for the 2017 calendar year. Elimination of the ROE collar effectively offsets the favorable or unfavorable impacts to Operating revenues associated with variations in delivery volumes associated with above or below normal weather, conditions increased Operating revenue netnumbers of purchased power expense when comparedcustomers or usage per customer. ComEd began recognizing the impacts of this change beginning in the first quarter of 2017. As of March 31, 2017, ComEd recorded an increase to Electric distribution revenues of approximately $16 million to eliminate the same periods in 2015.unfavorable weather and load impacts during the first quarter of 2017.
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 a30-year period in ComEd’s service territory with cooling degree days generally having a more significant impact to ComEd, particularly during the summer months. The changes in heating and cooling degree days in ComEd’s service territory for the three and nine months ended September 30,March 31, 2017 and 2016, and 2015, consisted of the following:
Heating and Cooling Degree-Days | % Change | |||||||||||||||||||
Three Months Ended September 30, | 2016 | 2015 | Normal | 2016 vs. 2015 | 2016 vs. Normal | |||||||||||||||
Heating Degree-Days | 23 | 55 | 119 | (58.2 | )% | (80.7 | )% | |||||||||||||
Cooling Degree-Days | 840 | 634 | 613 | 32.5 | % | 37.0 | % | |||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||
Heating Degree-Days | 3,678 | 4,373 | 4,048 | (15.9 | )% | (9.1 | )% | |||||||||||||
Cooling Degree-Days | 1,130 | 805 | 831 | 40.4 | % | 36.0 | % |
Volume. For the three and nine months ended September 30, 2016, Revenue net of purchased power expense increased as a result of higher delivery volume, exclusive of the effects of weather, reflecting increased average usage per residential customer as compared to the same periods in 2015.
Heating and Cooling Degree-Days | % Change | |||||||||||||||||||
Three Months Ended March 31, | 2017 | 2016 | Normal | 2017 vs. 2016 | 2017 vs. Normal | |||||||||||||||
Heating Degree-Days | 2,650 | 2,900 | 3,141 | (8.6 | )% | (15.6 | )% | |||||||||||||
Cooling Degree-Days | — | — | — | n/a | n/a |
Electric Distribution Revenue. EIMA provides for a performance-based formula rate, tariff, 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. Under EIMA, electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. ComEd’s allowed ROE is the annual average rate on30-year treasury notes plus 580 basis points,points. In addition, ComEd’s allowed ROE is subject to a collarreduction if ComEd does not deliver the reliability and customer service benefits to which it has committed over theten-year life of plus or minus 50 basis points. Therefore, the collar limits favorable and unfavorable impacts of weather and load on revenue.investment program. During the three and nine months ended September 30, 2016, ComEd recorded increasedMarch 31, 2017, electric distribution revenue increased primarily due to revenue decoupling impacts (as described above), increased capital investment, increased Depreciation expense, and depreciation expense, partially offset by lowerhigher allowed ROE due to a decreasean increase in treasury rates.rates, as compared to the same period in 2016. See Depreciation and amortization expense discussions below, and Note 5 — 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, 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. For the three and nine months ended September 30, 2016,March 31, 2017, ComEd recorded increased transmission revenue due to increased capital investment, higher depreciation expense and increased highest daily peak load as compared to the same period in 2015.2016. See Operating and maintenance expense below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs. This represents the change in Operating revenuerevenues collected under approved riders to recover costs incurred for regulatory programs such as ComEd’s energy efficiency and demand response and purchased power administrative costs. The riders are designed to provide full and current cost recovery. An equal and offsetting amount has been included in Operating and maintenance expense. See Operating and maintenance expense discussion below for additional information on included programs.
Uncollectible Accounts Recovery, Net. Uncollectible accounts recovery, net represents recoveries under ComEd’s uncollectible accounts tariff. See Operating and maintenance expense discussion below for additional information on this tariff.
Pricing and Customer Mix. For the three and nine months ended September 30, 2016, the decrease in Revenue net of purchased power as a result of pricing and customer mix is primarily attributable to lower overall effective rates due to increased usage across all major customer classes and change in customer mix as compared to the same period in 2015.
Other. Other revenue, which can vary period to period, includes rental revenue, revenue related to late payment charges, assistance provided to other utilities through mutual assistance programs, recoveries of environmental costs associated with MGP sites, and recoveries of energy procurement costs.
Operating and Maintenance Expense
Three Months Ended September 30, | Increase (Decrease) | Nine Months Ended September 30, | Increase (Decrease) | |||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||||||||||
Operating and maintenance expense —baseline | $ | 336 | $ | 338 | $ | (2 | ) | $ | 993 | $ | 1,005 | $ | (12 | ) | ||||||||||
Operating and maintenance expense —regulatory required programs(a) | 41 | 66 | $ | (25 | ) | 120 | 161 | (41 | ) | |||||||||||||||
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Total operating and maintenance expense | $ | 377 | $ | 404 | $ | (27 | ) | $ | 1,113 | $ | 1,166 | $ | (53 | ) | ||||||||||
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Three Months Ended March 31, | Increase (Decrease) | |||||||||||
2017 | 2016 | |||||||||||
Operating and maintenance expense — baseline | $ | 313 | $ | 331 | $ | (18 | ) | |||||
Operating and maintenance expense — regulatory required programs(a) | 57 | 37 | 20 | |||||||||
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Total operating and maintenance expense | $ | 370 | $ | 368 | $ | 2 | ||||||
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(a) | Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating |
The changesincrease in Operating and maintenance expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015,2016, consisted of the following:
Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | Three Months Ended March 31, 2017 | ||||||||||
Increase (Decrease) | Increase (Decrease) | Increase (Decrease) | ||||||||||
Baseline | ||||||||||||
Labor, other benefits, contracting and materials | $ | 3 | $ | (2 | ) | $ | (6 | ) | ||||
Pension and non-pension postretirement benefits expense(a) | (6 | ) | (16 | ) | ||||||||
Pension andnon-pension postretirement benefits expense | 1 | |||||||||||
Storm-related costs | 2 | 8 | (7 | ) | ||||||||
Uncollectible accounts expense — provision | 3 | 4 | (3 | ) | ||||||||
Uncollectible accounts expense — recovery, net | (1 | ) | (19 | ) | 1 | |||||||
BSC costs | (2 | ) | 20 | 1 | ||||||||
Other | (1 | ) | (7 | ) | (5 | ) | ||||||
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(2 | ) | (12 | ) | (18 | ) | |||||||
Regulatory required programs | ||||||||||||
Energy efficiency and demand response programs | (25 | ) | (41 | ) | 20 | |||||||
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Increase in operating and maintenance expense | $ | 2 | ||||||||||
(25 | ) | (41 | ) |
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Total increase (decrease) | $ | (27 | ) | $ | (53 | ) | ||||||
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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 |
months ended |
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Depreciation and Amortization Expense
The increase in Depreciation and amortization expense during the three and nine months ended September 30, 2016,March 31, 2017, compared to the same periodsperiod in 2015,2016, consisted of the following:
Three Months Ended September 30, 2016 Increase (Decrease) | Nine Months Ended September 30, 2016 Increase (Decrease) | Three Months Ended March 31, 2017 Increase (Decrease) | ||||||||||
Depreciation expense(a) | $ | 16 | $ | 43 | $ | 16 | ||||||
Regulatory asset amortization | (1 | ) | (7 | ) | (1 | ) | ||||||
Other | 5 | 10 | 4 | |||||||||
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Total increase | $ | 20 | $ | 46 | $ | 19 | ||||||
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Taxes Other Than Income
Taxes other than income, which can vary periodyear to period,year, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income taxes remained relatively consistent duringfor the three and nine months ended September 30, 2016,March 31, 2017, compared to the same periodsperiod in 2015.2016.
Gain on Sales of Assets
The increasedecrease in Gain on sales of assets during the three and nine months ended September 30, 2016,March 31, 2017, compared to the same periodsperiod in 2015,2016, is primarily due to the sale of land during March 2016.
Interest Expense, Net
The changes in interestInterest expense, net, forremained relatively consistent during the three and nine months ended September 30, 2016,March 31, 2017, compared to the same periodsperiod in 2015, consisted of the following:2016.
Three Months Ended September 30, 2016 Increase (Decrease) | Nine Months Ended September 30, 2016 Increase (Decrease) | |||||||
Interest expense related to uncertain tax positions(a) | $ | 106 | $ | 110 | ||||
Interest expense on debt (including financing trusts) | 11 | 20 | ||||||
Other | (3 | ) | (4 | ) | ||||
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Increase in interest expense, net | $ | 114 | $ | 126 | ||||
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Other, Net
The changes in other,Other, net, forremained relatively consistent during the three and nine months ended September 30, 2016,March 31, 2017, compared to the same periodsperiod in 2015, consisted of the following:2016.
Three Months Ended September 30, 2016 Increase (Decrease) | Nine Months Ended September 30, 2016 Increase (Decrease) | |||||||
Other income and deductions, net(a) | $ | 89 | $ | 92 | ||||
AFUDC equity | (4 | ) | (6 | ) | ||||
Other | (1 | ) | — | |||||
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Increase in other, net | $ | 84 | $ | 86 | ||||
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Effective Income Tax Rate
ComEd’s effective income tax rate was 67.0%39.5% and 39.9%40.1% for the three months ended September 30,March 31, 2017 and 2016, and 2015, respectively. ComEd’s effective income tax rate was 45.1% and 40.0% for the nine months ended September 30, 2016 and 2015, respectively. The increase in the effective income tax rate for the three and nine months ended September 30, 2016 compared to the same periods in 2015 is primarily due to a non-deductible penalty. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
ComEd Electric Operating Statistics and Revenue Detail
Retail Deliveries to Customers (in | Three Months Ended September 30, | Weather-Normal % Change | Nine Months Ended September 30, | Weather-Normal % Change | ||||||||||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, | Weather-Normal % Change | |||||||||||||||||||||||||||||||||||||||||||||||
Retail Deliveries to Customers (in | 2016 | 2015 | % Change | Weather-Normal % Change | 2016 | 2015 | % Change | Weather-Normal % Change | 2017 | 2016 | % Change | |||||||||||||||||||||||||||||||||||||
Residential | 9,014 | 7,919 | 13.8 | % | 1.0 | % | 21,738 | 20,602 | 5.5 | % | (0.1 | )% | 6,241 | 6,376 | (2.1 | )% | 0.3 | % | ||||||||||||||||||||||||||||||
Small commercial & industrial | 8,833 | 8,579 | 3.0 | % | (0.2 | )% | 24,447 | 24,305 | 0.6 | % | (0.1 | )% | 7,709 | 7,879 | (2.2 | )% | (1.0 | )% | ||||||||||||||||||||||||||||||
Large commercial & industrial | 7,565 | 7,250 | 4.3 | % | 2.0 | % | 21,057 | 20,807 | 1.2 | % | 1.0 | % | 6,683 | 6,756 | (1.1 | )% | (0.3 | )% | ||||||||||||||||||||||||||||||
Public authorities & electric railroads | 308 | 295 | 4.4 | % | 4.4 | % | 947 | 964 | (1.8 | )% | (0.3 | )% | 344 | 361 | (4.7 | )% | (3.4 | )% | ||||||||||||||||||||||||||||||
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Total retail deliveries | 25,720 | 24,043 | 7.0 | % | 0.9 | % | 68,189 | 66,678 | 2.3 | % | 0.2 | % | 20,977 | 21,372 | (1.8 | )% | (0.4 | )% | ||||||||||||||||||||||||||||||
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Number of Electric Customers | As of September 30, | |||||||||||||||||||||||||||||||||||||||||||||||
As of March 31, | ||||||||||||||||||||||||||||||||||||||||||||||||
Number of Electric Customers | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||||
3,578,846 | 3,524,253 | 3,605,498 | 3,566,896 | |||||||||||||||||||||||||||||||||||||||||||||
Small commercial & industrial | 372,603 | 369,151 | 375,617 | 372,254 | ||||||||||||||||||||||||||||||||||||||||||||
Large commercial & industrial | 2,010 | 1,996 | 2,000 | 1,955 | ||||||||||||||||||||||||||||||||||||||||||||
Public authorities & electric railroads | 4,738 | 4,826 | 4,818 | 4,821 | ||||||||||||||||||||||||||||||||||||||||||||
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Total | 3,958,197 | 3,900,226 | 3,987,933 | 3,945,926 | ||||||||||||||||||||||||||||||||||||||||||||
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Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||||||||||||||
Electric Revenue | 2016 | 2015 | % Change | 2016 | 2015 | % Change | 2017 | 2016 | % Change | |||||||||||||||||||||||||||
Retail Sales(a) | ||||||||||||||||||||||||||||||||||||
Residential | $ | 786 | $ | 690 | 13.9 | % | $ | 2,018 | $ | 1,785 | 13.1 | % | $ | 627 | $ | 609 | 3.0 | % | ||||||||||||||||||
Small commercial & industrial | 356 | 361 | (1.4 | )% | 1,007 | 1,029 | (2.1 | )% | 335 | 321 | 4.4 | % | ||||||||||||||||||||||||
Large commercial & industrial | 126 | 121 | 4.1 | % | 350 | 339 | 3.2 | % | 108 | 107 | 0.9 | % | ||||||||||||||||||||||||
Public authorities & electric railroads | 10 | 10 | — | % | 33 | 33 | — | % | 12 | 12 | — | % | ||||||||||||||||||||||||
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Total retail | 1,278 | 1,182 | 8.1 | % | 3,408 | 3,186 | 7.0 | % | 1,082 | 1,049 | 3.1 | % | ||||||||||||||||||||||||
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Other revenue(b) | 219 | 194 | 12.9 | % | 623 | 523 | 19.1 | % | 216 | 200 | 8.0 | % | ||||||||||||||||||||||||
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Total electric revenue(c) | $ | 1,497 | $ | 1,376 | 8.8 | % | $ | 4,031 | $ | 3,709 | 8.7 | % | $ | 1,298 | $ | 1,249 | 3.9 | % | ||||||||||||||||||
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(a) | Reflects delivery revenue and volume from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier, as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy and transmission. |
(b) | Other revenue primarily includes transmission revenue from PJM. Other revenue also includes rental revenue, revenue related to late payment charges, revenue from other utilities for mutual assistance programs and recoveries of remediation costs associated with MGP sites. |
(c) | Includes operating revenues from affiliates totaling |
Three Months Ended September 30, | Favorable (Unfavorable) Variance | Nine Months Ended September 30, | Favorable (Unfavorable) Variance | Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||||||||||||
Operating revenues | $ | 788 | $ | 740 | $ | 48 | $ | 2,293 | $ | 2,386 | $ | (93 | ) | $ | 796 | $ | 841 | $ | (45 | ) | ||||||||||||||||
Purchased power and fuel | 272 | 278 | 6 | 809 | 953 | 144 | ||||||||||||||||||||||||||||||
Purchased power and fuel expense | 287 | 321 | 34 | |||||||||||||||||||||||||||||||||
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Revenue net of purchased power and fuel(a) | 516 | 462 | 54 | 1,484 | 1,433 | 51 | ||||||||||||||||||||||||||||||
Revenues net of purchased power and fuel expense(a) | 509 | 520 | (11 | ) | ||||||||||||||||||||||||||||||||
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Other operating expenses | ||||||||||||||||||||||||||||||||||||
Operating and maintenance | 199 | 196 | (3 | ) | 604 | 609 | 5 | 208 | 215 | 7 | ||||||||||||||||||||||||||
Depreciation and amortization | 67 | 68 | 1 | 201 | 198 | (3 | ) | 71 | 67 | (4 | ) | |||||||||||||||||||||||||
Taxes other than income | 46 | 44 | (2 | ) | 126 | 125 | (1 | ) | 38 | 42 | 4 | |||||||||||||||||||||||||
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Total other operating expenses | 312 | 308 | (4 | ) | 931 | 932 | 1 | 317 | 324 | 7 | ||||||||||||||||||||||||||
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Gain on sales of assets | — | — | — | — | 1 | (1 | ) | |||||||||||||||||||||||||||||
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Operating income | 204 | 154 | 50 | 553 | 502 | 51 | 192 | 196 | (4 | ) | ||||||||||||||||||||||||||
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Other income and (deductions) | ||||||||||||||||||||||||||||||||||||
Interest expense, net | (30 | ) | (28 | ) | (2 | ) | (92 | ) | (84 | ) | (8 | ) | (31 | ) | (31 | ) | — | |||||||||||||||||||
Other, net | 2 | 1 | 1 | 6 | 3 | 3 | 2 | 2 | — | |||||||||||||||||||||||||||
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Total other income and (deductions) | (28 | ) | (27 | ) | (1 | ) | (86 | ) | (81 | ) | (5 | ) | (29 | ) | (29 | ) | — | |||||||||||||||||||
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Income before income taxes | 176 | 127 | 49 | 467 | 421 | 46 | 163 | 167 | (4 | ) | ||||||||||||||||||||||||||
Income taxes | 54 | 37 | (17 | ) | 121 | 122 | 1 | 36 | 43 | 7 | ||||||||||||||||||||||||||
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Net income attributable to common shareholder | $ | 122 | $ | 90 | $ | 32 | $ | 346 | $ | 299 | $ | 47 | ||||||||||||||||||||||||
Net income | $ | 127 | $ | 124 | $ | 3 | ||||||||||||||||||||||||||||||
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(a) | PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide information that can be used to |
evaluate its net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense and revenue net of fuel expense figures are not presentations defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report. |
Net Income Attributable to Common Shareholder
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.March 31, 2016. PECO’s Net income attributable to common shareholder increased from the same period in 2015,2016, primarily due to an increase in Revenue net of purchased power and fuel expense as a result of increased electric distribution revenue pursuant to the 2015 PAPUC authorized electric distribution rate increase effective January 1, 2016, as well as favorable summer weather.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. PECO’s Net income attributable to common shareholder increased from the same period in 2015, primarily due to an increase in Revenue net of purchased power and fuel expense as a result of increased electric distribution revenue pursuant to the 2015 PAPUC authorized electric distribution rate increase effective January 1, 2016, partially offset by unfavorable winter weather as well as a lower income tax expense as a result of an increase in the gasa higher tax repairs deduction and a cumulative adjustment related to an anticipated gas repairs tax return accounting method change.deduction.
Operating Revenues Net of Purchased Power and Fuel Expense
Electric and natural gas revenue and purchased power and fuel expense are affected by fluctuations in commodity procurement costs. PECO’s electric supply and natural gas cost rates charged to customers are subject to adjustments at least quarterly that are designed to recover or refund the difference between the actual cost of electric supply and natural gas and the amount included in rates in accordance with the PAPUC’s GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on electric and natural gas revenue net of purchased power and fuel expense.
Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All PECO customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers’ choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service. Customer choice program activity has no impact on electric and natural gas revenue net of purchased power and fuel expense.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30,March 31, 2017 and 2016, and 2015, consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||
Electric | 69 | % | 69 | % | 70 | % | 69 | % | 70 | % | 69 | % | ||||||||||||
Natural Gas | 31 | % | 31 | % | 26 | % | 24 | % | 25 | % | 25 | % |
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30,March 31, 2017 and 2016 and 2015 consisted of the following:
September 30, 2016 | September 30, 2015 | |||||||||||||||
Number of customers | % of total retail customers | Number of customers | % of total retail customers | |||||||||||||
Electric | 581,600 | 36 | % | 558,300 | 35 | % | ||||||||||
Natural Gas | 81,300 | 16 | % | 81,100 | 16 | % |
Electric Natural Gas March 31, 2017 March 31, 2016 Number of
customers % of total
retail
customers Number of
customers % of total
retail
customers 589,700 36 % 570,000 35 % 81,300 16 % 80,600 16 %
The changes in PECO’s operatingOperating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 consisted of the following:
Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | Three Months Ended March 31, 2017 | ||||||||||||||||||||||||||||||||||
Increase (Decrease) | Increase (Decrease) | Increase (Decrease) | ||||||||||||||||||||||||||||||||||
Electric | Natural Gas | Total | Electric | Natural Gas | Total | Electric | Natural Gas | Total | ||||||||||||||||||||||||||||
Weather | $ | 31 | $ | — | $ | 31 | $ | (19 | ) | $ | (28 | ) | $ | (47 | ) | $ | 2 | $ | 1 | $ | 3 | |||||||||||||||
Volume | (2 | ) | — | (2 | ) | 7 | 3 | 10 | (5 | ) | — | (5 | ) | |||||||||||||||||||||||
Pricing | 36 | — | 36 | 137 | (1 | ) | 136 | (2 | ) | — | (2 | ) | ||||||||||||||||||||||||
Regulatory required programs | (9 | ) | — | (9 | ) | (43 | ) | — | (43 | ) | (9 | ) | — | (9 | ) | |||||||||||||||||||||
Other | (2 | ) | — | (2 | ) | (6 | ) | 1 | (5 | ) | 3 | (1 | ) | 2 | ||||||||||||||||||||||
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Total increase (decrease) | $ | 54 | $ | — | $ | 54 | $ | 76 | $ | (25 | ) | $ | 51 | |||||||||||||||||||||||
Total decrease | $ | (11 | ) | $ | — | $ | (11 | ) | ||||||||||||||||||||||||||||
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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 months ended September 30, 2016March 31, 2017 compared to the same period in 2015,2016, Operating revenue net of purchased power and fuel expense was higher due to the impact of favorable weather conditions in PECO’s service territory. During the nine months ended September 30, 2016 compared to the same period in 2015, Operating revenue net of purchased power and fuel expense was lower due to the impact of unfavorable weather conditions in PECO’s service territory.relatively consistent.
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 a30-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, 2016March 31, 2017 compared to the same periods in 20152016 and normal weather consisted of the following:
Heating and Cooling Degree-Days | Normal | % Change | Normal | % Change | ||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, | 2016 | 2015 | 2016 vs. 2015 | 2016 vs. Normal | ||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, | 2017 | 2016 | Normal | 2017 vs. 2016 | 2017 vs. Normal | |||||||||||||||||||||||||||||||||||
Heating Degree-Days | 10 | — | 38 | N/A | (73.7 | )% | 2,094 | 2,137 | (2.0 | )% | (15.4 | )% | ||||||||||||||||||||||||||||
Cooling Degree-Days | 1,288 | 1,186 | 929 | 8.6 | % | 38.6 | % | — | 5 | — | (100.0 | )% | n/a | |||||||||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||
Heating Degree-Days | 2,616 | 3,264 | 2,981 | (19.9 | )% | (12.2 | )% | |||||||||||||||||||||||||||||||||
Cooling Degree-Days | 1,684 | 1,699 | 1,278 | (0.9 | )% | 31.8 | % |
Volume. The decrease in Operating revenue net of purchased power expense related to delivery volume, exclusive of the effects of weather, for the three months ended March 31, 2017 compared to the same period in 2016, primarily reflects the impacts of energy efficiency initiatives on customer usage as well as the impacts of an extra day of usage due to the leap year in 2016, partially offset by moderate economic and customer growth. Operating revenue net of purchased fuel expense related to delivery volume, exclusive of the effects of weather, for the three months ended September 30, 2016March 31, 2017 compared to the same period in 2015,2016, remained relatively consistent. The increase in Operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the nine months ended September 30, 2016 compared to the same periods in 2015, primarily reflects a shift in the volume profile across classes from lower priced classes to higher priced classes for electric, as well as the impact of moderate economic and customer growth partially offset by energy efficiency initiatives on customer usages for electric and natural gas.
Pricing. The increase in Operating revenues net of purchased power and fuel expense as a result of pricing for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015 primarily reflects an increase in electric distribution rates charged to customers. The increase in electric distribution rates was effective January 1, 2016 in accordance with the 2015 PAPUC approved electric distribution rate case settlement. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements in the 2015 Form 10-K for further information.remained relatively consistent.
Regulatory Required Programs. This represents the change in Operating revenue collected under approved riders to recover costs incurred for regulatory programs such as smart meter, energy efficiency 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 Operating and maintenance expense, Depreciation and amortization expense and Income taxes. The decrease in revenue from regulatory required programs for the three and nine months ended September 30, 2016 compared to the same periods in 2015 is primarily the result of smart meter costs reflected in base rates in 2016 in accordance with the 2015 PAPUC approved electric distribution rate case settlement effective January 1, 2016 versus through a rider mechanism in 2015. Refer to the Operating and maintenance expense discussion below for additional information on included programs.
Other. Other revenue, which can vary period to period, primarily includes wholesale transmission revenue, rental revenue, revenue related to late payment charges and assistance provided to other utilities through mutual assistance programs.
Operating and Maintenance Expense
Three Months Ended September 30, | Increase (Decrease) | Nine Months Ended September 30, | Increase (Decrease) | Three Months Ended March 31, | Increase (Decrease) | |||||||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||||||||||||
Operating and maintenance expense — baseline | $ | 185 | $ | 170 | $ | 15 | $ | 545 | $ | 528 | $ | 17 | $ | 196 | $ | 195 | $ | 1 | ||||||||||||||||||
Operating and maintenance expense — regulatory required programs(a) | 14 | 26 | (12 | ) | 59 | 81 | (22 | ) | 12 | 20 | (8 | ) | ||||||||||||||||||||||||
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Total operating and maintenance expense | $ | 199 | $ | 196 | $ | 3 | $ | 604 | $ | 609 | $ | (5 | ) | $ | 208 | $ | 215 | $ | (7 | ) | ||||||||||||||||
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(a) | Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in operating revenue. |
The changes in Operating and maintenance expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015,2016, consisted of the following:
Three Months Ended September 30, 2016 | Nine months ended September 30, 2016 | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Baseline | ||||||||
Labor, other benefits, contracting and materials | $ | 8 | $ | 16 | ||||
Storm-related costs | 4 | (9 | ) | |||||
Pension and non-pension postretirement benefits expense | (1 | ) | (3 | ) | ||||
PHI merger and integration costs | 1 | 3 | ||||||
BSC costs(a) | 1 | 22 | ||||||
Uncollectible accounts expense | 1 | (12 | ) | |||||
Other | 1 | — | ||||||
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15 | 17 | |||||||
Regulatory Required Programs | ||||||||
Smart meter | (6 | ) | (20 | ) | ||||
Energy efficiency | (6 | ) | (1 | ) | ||||
Other | — | (1 | ) | |||||
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(12 | ) | (22 | ) | |||||
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Total decrease | $ | 3 | $ | (5 | ) | |||
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Baseline Labor, other benefits, contracting and materials Storm-related costs Pension andnon-pension postretirement benefits expense BSC costs Uncollectible accounts expense Other Regulatory Required Programs Energy efficiency Total decrease Three months ended
March 31, 2017 Increase
(Decrease) $ 3 (1 ) (1 ) (4 ) 1 3 1 (8 ) (8 ) $ (7 )
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015,2016, consisted of the following:an increase of $4 million.
Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Depreciation and amortization expense | $ | — | $ | 2 | ||||
Regulatory asset amortization | (1 | ) | 1 | |||||
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Total increase (decrease) | $ | (1 | ) | $ | 3 | |||
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Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income decreased for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015 remained relatively consistent.2016 due to a decrease in gross receipts tax driven by decreases in electric revenue, which was impacted primarily by energy efficiency programs.
Interest Expense, Net
The increase in Interest expense, net for the three and nine months ended September 30, 2016March 31, 2017 remained consistent compared to the same periodsperiod in 2015 primarily reflects an increase in interest expense due to the issuance of First and Refunding Mortgage Bonds in October 2015.2016.
Other, Net
Other, net for the three and nine months ended September 30, 2016March 31, 2017 remained relatively consistent compared to the same periodsperiod in 2015.2016.
Effective Income Tax Rate
PECO’s effective income tax rate was 30.7%22.1% and 29.1%25.7% for the three months ended September 30,March 31, 2017 and 2016, and 2015, respectively. PECO’s effective income tax rate was 25.9% and 29.0% for the nine months ended September 30, 2016 and 2015, respectively. The decrease in the effective income tax rate for the nine months ended September 30, 2016 compared to the same period in 2015 is primarily due to an increase in the gas repairs deduction and a cumulative adjustment related to an anticipated gas repairs tax return accounting method change. See Note 11—11 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.
PECO Electric Operating Statistics and Revenue Detail
Retail Deliveries to Customers (in | Three Months Ended September 30, | % Change | Weather - Normal % Change | Nine Months Ended September 30, | % Change | Weather - Normal % Change | ||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||||||||||||||||||
Retail Deliveries(a) | ||||||||||||||||||||||||||||||||
Residential | 4,358 | 3,940 | 10.6 | % | 1.5 | % | 10,682 | 10,929 | (2.3 | )% | 1.3 | % | ||||||||||||||||||||
Small commercial & industrial | 2,324 | 2,219 | 4.7 | % | 0.5 | % | 6,236 | 6,306 | (1.1 | )% | 1.7 | % | ||||||||||||||||||||
Large commercial & industrial | 4,234 | 4,227 | 0.2 | % | (2.9 | )% | 11,598 | 11,744 | (1.2 | )% | (1.9 | )% | ||||||||||||||||||||
Public authorities & electric railroads | 240 | 224 | 7.1 | % | 7.1 | % | 672 | 667 | 0.7 | % | 0.7 | % | ||||||||||||||||||||
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Total retail deliveries | 11,156 | 10,610 | 5.1 | % | (0.4 | )% | 29,188 | 29,646 | (1.5 | )% | 0.1 | % | ||||||||||||||||||||
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As of September 30, | ||||||||||||||||||||||||||||||||
Number of Electric Customers | 2016 | 2015 | ||||||||||||||||||||||||||||||
Residential | 1,451,533 | 1,439,951 | ||||||||||||||||||||||||||||||
Small commercial & industrial | 149,646 | 148,920 | ||||||||||||||||||||||||||||||
Large commercial & industrial | 3,094 | 3,093 | ||||||||||||||||||||||||||||||
Public authorities & electric railroads | 9,820 | 9,801 | ||||||||||||||||||||||||||||||
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Total | 1,614,093 | 1,601,765 | ||||||||||||||||||||||||||||||
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Three Months Ended March 31, | % Change | Weather - Normal % Change | ||||||||||||||||||||||||||||||||||||||
Retail Deliveries to Customers (in GWhs) | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||
Retail Deliveries(a) | ||||||||||||||||||||||||||||||||||||||||
Residential | 3,378 | 3,415 | (1.1 | )% | (1.5 | )% | ||||||||||||||||||||||||||||||||||
Small commercial & industrial | 1,976 | 2,025 | (2.4 | )% | (3.0 | )% | ||||||||||||||||||||||||||||||||||
Large commercial & industrial | 3,626 | 3,594 | 0.9 | % | 0.6 | % | ||||||||||||||||||||||||||||||||||
Public authorities & electric railroads | 224 | 227 | (1.3 | )% | (1.3 | )% | ||||||||||||||||||||||||||||||||||
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Total retail deliveries | 9,204 | 9,261 | (0.6 | )% | (1.0 | )% | ||||||||||||||||||||||||||||||||||
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As of March 31, | ||||||||||||||||||||||||||||||||||||||||
Number of Electric Customers | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||
Residential | 1,461,662 | 1,449,470 | ||||||||||||||||||||||||||||||||||||||
Small commercial & industrial | 150,580 | 149,388 | ||||||||||||||||||||||||||||||||||||||
Large commercial & industrial | 3,100 | 3,092 | ||||||||||||||||||||||||||||||||||||||
Public authorities & electric railroads | 9,798 | 9,807 | ||||||||||||||||||||||||||||||||||||||
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Total | 1,625,140 | 1,611,757 | ||||||||||||||||||||||||||||||||||||||
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Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | % Change | |||||||||||||||||||||||||||||||||||||
Electric Revenue | 2016 | 2015 | % Change | 2016 | 2015 | % Change | 2017 | 2016 | ||||||||||||||||||||||||||||||||
Retail Sales(a) | ||||||||||||||||||||||||||||||||||||||||
Residential | $ | 513 | $ | 461 | 11.3 | % | $ | 1,278 | $ | 1,276 | 0.2 | % | $ | 382 | $ | 410 | (6.8 | )% | ||||||||||||||||||||||
Small commercial & industrial | 109 | 113 | (3.5 | )% | 334 | 330 | 1.2 | % | 97 | 119 | (18.5 | )% | ||||||||||||||||||||||||||||
Large commercial & industrial | 59 | 58 | 1.7 | % | 182 | 166 | 9.6 | % | 52 | 58 | (10.3 | )% | ||||||||||||||||||||||||||||
Public authorities & electric railroads | 8 | 8 | — | % | 25 | 23 | 8.7 | % | 8 | 8 | — | % | ||||||||||||||||||||||||||||
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Total retail | 689 | 640 | 7.7 | % | 1,819 | 1,795 | 1.3 | % | 539 | 595 | (9.4 | )% | ||||||||||||||||||||||||||||
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Other revenue(b) | 51 | 51 | — | % | 152 | 155 | (1.9 | )% | 51 | 49 | 4.1 | % | ||||||||||||||||||||||||||||
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Total electric revenue(c) | $ | 740 | $ | 691 | 7.1 | % | $ | 1,971 | $ | 1,950 | 1.1 | % | $ | 590 | $ | 644 | (8.4 | )% | ||||||||||||||||||||||
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(a) | Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission. |
(b) | Other revenue primarily includes transmission revenue from PJM and wholesale electric revenue, in addition to rental income. |
(c) | Includes operating revenues from affiliates totaling |
PECO Natural Gas Operating Statistics and Revenue Detail
Three Months Ended September 30, | % Change | Weather - Normal % Change | Nine Months Ended September 30, | % Change | Weather - Normal % Change | |||||||||||||||||||||||||||
Deliveries to Customers (in mmcf) | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||||||||||||||
Retail Delivery | ||||||||||||||||||||||||||||||||
Retail sales(a) | 3,494 | 3,639 | (4.0 | )% | (2.4 | )% | 38,488 | 45,734 | (15.8 | )% | 1.8 | % | ||||||||||||||||||||
Transportation and other | 7,315 | 7,457 | (1.9 | )% | (3.3 | )% | 20,917 | 21,585 | (3.1 | )% | 1.1 | % | ||||||||||||||||||||
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Total natural gas deliveries | 10,809 | 11,096 | (2.6 | )% | (3.0 | )% | 59,405 | 67,319 | (11.8 | )% | 1.5 | % | ||||||||||||||||||||
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As of September 30, | ||||||||||||||||||||||||||||||||
Number of Natural Gas Customers | 2016 | 2015 | ||||||||||||||||||||||||||||||
Residential | 470,024 | 465,023 | ||||||||||||||||||||||||||||||
Commercial & industrial | 42,997 | 42,544 | ||||||||||||||||||||||||||||||
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Total retail | 513,021 | 507,567 | ||||||||||||||||||||||||||||||
Transportation | 802 | 837 | ||||||||||||||||||||||||||||||
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Total | 513,823 | 508,404 | ||||||||||||||||||||||||||||||
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Three Months Ended March 31, | % Change | Weather - Normal % Change | ||||||||||||||||||||||||||||||||||||||
Deliveries to Customers (in mmcf) | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||
Retail Delivery | ||||||||||||||||||||||||||||||||||||||||
Retail sales(a) | 27,211 | 27,111 | 0.4 | % | (0.4 | )% | ||||||||||||||||||||||||||||||||||
Transportation and other | 7,689 | 7,696 | (0.1 | )% | (0.8 | )% | ||||||||||||||||||||||||||||||||||
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Total natural gas deliveries | 34,900 | 34,807 | 0.3 | % | (0.4 | )% | ||||||||||||||||||||||||||||||||||
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As of March 31, | ||||||||||||||||||||||||||||||||||||||||
Number of Natural Gas Customers | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||
Residential | 473,972 | 468,808 | ||||||||||||||||||||||||||||||||||||||
Commercial & industrial | 43,709 | 43,313 | ||||||||||||||||||||||||||||||||||||||
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Total retail | 517,681 | 512,121 | ||||||||||||||||||||||||||||||||||||||
Transportation | 775 | 817 | ||||||||||||||||||||||||||||||||||||||
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Total | 518,456 | 512,938 | ||||||||||||||||||||||||||||||||||||||
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Three Months Ended September 30, | % Change | Nine Months Ended September 30, | % Change | Three Months Ended March 31, | % Change | |||||||||||||||||||||||||||||||||||
Natural Gas Revenue | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||
Retail Sales | ||||||||||||||||||||||||||||||||||||||||
Retail sales(a) | $ | 41 | $ | 42 | (2.4 | )% | $ | 298 | $ | 410 | (27.3 | )% | $ | 197 | $ | 187 | 5.3 | % | ||||||||||||||||||||||
Transportation and other | 7 | 7 | — | % | 24 | 26 | (7.7 | )% | 9 | 10 | (10.0 | )% | ||||||||||||||||||||||||||||
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Total natural gas revenues(b) | $ | 48 | $ | 49 | (2.0 | )% | $ | 322 | $ | 436 | (26.1 | )% | $ | 206 | $ | 197 | 4.6 | % | ||||||||||||||||||||||
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(a) | Reflects delivery volumes and revenue 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. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas. |
(b) | Includes operating revenues from affiliates totaling less than $1 million for both three months ended |
Three Months Ended September 30, | Favorable (Unfavorable) Variance | Nine Months Ended September 30, | Favorable (Unfavorable) Variance | Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||||||||||||
Operating revenues | $ | 812 | $ | 725 | $ | 87 | $ | 2,421 | $ | 2,388 | $ | 33 | $ | 951 | $ | 929 | $ | 22 | ||||||||||||||||||
Purchased power and fuel | 360 | 311 | (49 | ) | 994 | 1,037 | 43 | |||||||||||||||||||||||||||||
Purchased power and fuel expense | 350 | 373 | 23 | |||||||||||||||||||||||||||||||||
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Revenue net of purchased power and fuel(a) | 452 | 414 | 38 | 1,427 | 1,351 | 76 | ||||||||||||||||||||||||||||||
Revenues net of purchased power and fuel expense(a) | 601 | 556 | 45 | |||||||||||||||||||||||||||||||||
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Other operating expenses | ||||||||||||||||||||||||||||||||||||
Operating and maintenance | 178 | 169 | (9 | ) | 588 | 499 | (89 | ) | 183 | 202 | 19 | |||||||||||||||||||||||||
Depreciation and amortization | 101 | 79 | (22 | ) | 307 | 271 | (36 | ) | 128 | 109 | (19 | ) | ||||||||||||||||||||||||
Taxes other than income | 58 | 57 | (1 | ) | 172 | 169 | (3 | ) | 62 | 58 | (4 | ) | ||||||||||||||||||||||||
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Total other operating expenses | 337 | 305 | (32 | ) | 1,067 | 939 | (128 | ) | 373 | 369 | (4 | ) | ||||||||||||||||||||||||
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Gain on Sale of Assets | — | 1 | (1 | ) | — | 1 | (1 | ) | ||||||||||||||||||||||||||||
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Operating income | 115 | 110 | 5 | 360 | 413 | (53 | ) | 228 | 187 | 41 | ||||||||||||||||||||||||||
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Other income and (deductions) | ||||||||||||||||||||||||||||||||||||
Interest expense, net | (28 | ) | (25 | ) | (3 | ) | (76 | ) | (73 | ) | (3 | ) | (27 | ) | (24 | ) | (3 | ) | ||||||||||||||||||
Other, net | 5 | 4 | 1 | 16 | 13 | 3 | 4 | 4 | — | |||||||||||||||||||||||||||
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Total other income and (deductions) | (23 | ) | (21 | ) | (2 | ) | (60 | ) | (60 | ) | — | (23 | ) | (20 | ) | (3 | ) | |||||||||||||||||||
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Income before income taxes | 92 | 89 | 3 | 300 | 353 | (53 | ) | 205 | 167 | 38 | ||||||||||||||||||||||||||
Income taxes | 36 | 35 | (1 | ) | 109 | 141 | 32 | 80 | 66 | (14 | ) | |||||||||||||||||||||||||
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Net income | 56 | 54 | 2 | 191 | 212 | (21 | ) | 125 | 101 | 24 | ||||||||||||||||||||||||||
Preference stock dividends | 2 | 3 | (1 | ) | 8 | 10 | (2 | ) | — | 3 | 3 | |||||||||||||||||||||||||
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Net income attributable to common shareholder | $ | 54 | $ | 51 | $ | 3 | $ | 183 | $ | 202 | $ | (19 | ) | $ | 125 | $ | 98 | $ | 27 | |||||||||||||||||
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(a) | BGE evaluates its operating performance using the |
Net Income Attributable to Common Shareholder
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015March 31, 2016. BGE’s Net income attributable to common shareholder for the three months ended September 30, 2016March 31, 2017 was higher than the same period in 2015,2016, primarily due to an increase in RevenueRevenues net of purchased power and fuel, primarilypredominantly as a result of an increase in transmission formula rate revenues, and higher electric and natural gas revenues as a result of the distribution rate orders issued by the MDPSC in June 2016 and July 2016. The increase in Revenue net of purchased power and fuel was partially offset by an increase in Depreciation and amortization expense due to the initiation of cost recovery of the AMI programs under the distribution rate orders issued by the MDPSC in June 2016 and July 2016.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. BGE’s Net income attributable to common shareholder for the nine months ended September 30, 2016 was lower than the same period in 2015, primarily due to an increase in Operating and maintenance expense as a result of
reducing certain regulatory assets and other long-lived assets stemming from certain cost disallowances contained within the final smart grid rate order issued by the MDPSC in June 2016 and increased storm costs. The lower net income was also due to an increase in Depreciation and amortization expense due to the initiation of cost recovery of the AMI programs under the distribution rate orders issued by the MDPSC in June 2016 and July 2016. These increases in Operating and maintenance expense and Depreciation and amortization expense were partially offset by an increase in Revenue net of purchased power and fuel, primarily as a result of an increase in transmission formula rate revenues, higher electric and natural gas revenues as a result of the distribution rate orders issued by the MDPSC in June 2016 and July 2016, and lower incomeOperating and maintenance expense mostly due to decreased storm costs. These items were partially offset by an increase in Depreciation and amortization expense primarily related to increased amortization of AMI meters and Income tax expense driven by lowerhigher taxable income.
Operating Revenues Net of Purchased Power and Fuel Expense
There are certain drivers to Operating revenuerevenues that are offset by their impact on Purchased power and fuel expense, such as commodity procurement costs and programs allowing customers to select a competitive electric generation or natural gas supplier. Operating revenuerevenues and Purchased power and fuel expense are affected by fluctuations in commodity procurement costs. BGE’s electric and natural gas rates charged to customers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electric
power and purchased natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodity programs, respectively.
Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in the number of customers electing to use a competitive electric generation or natural gas supplier. All BGE customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers’ choice of suppliers does not impact the volume of deliveries, but does affect revenue collected from customers related to supplied energy and natural gas service.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30,March 31, 2017 and 2016 and 2015, consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||
Electric | 58 | % | 60 | % | 59 | % | 59 | % | 58 | % | 57 | % | ||||||||||||
Natural Gas | 80 | % | 76 | % | 59 | % | 54 | % | 48 | % | 49 | % |
The number of retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30,March 31, 2017 and 2016 and 2015 consisted of the following:
September 30, 2016 | September 30, 2015 | |||||||||||||||
Number of Customers | % of total retail customers | Number of customers | % of total retail customers | |||||||||||||
Electric | 334,100 | 26 | % | 346,400 | 28 | % | ||||||||||
Natural Gas | 150,000 | 23 | % | 154,900 | 24 | % |
Electric Natural Gas March 31, 2017 March 31, 2016 Number
of
Customers % of total
retail
customers Number
of
customers % of total
retail
customers 339,600 27 % 341,800 27 % 149,300 22 % 153,500 23 %
The changes in BGE’s operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2016,March 31, 2017, compared to the same periodsperiod in 2015,2016, consisted of the following:
Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | Three Months Ended March 31, 2017 | ||||||||||||||||||||||||||||||||||
Increase (Decrease) | Increase (Decrease) | Increase (Decrease) | ||||||||||||||||||||||||||||||||||
Electric | Gas | Total | Electric | Gas | Total | Electric | Gas | Total | ||||||||||||||||||||||||||||
Distribution rate increase | $ | 16 | $ | 4 | $ | 20 | $ | 22 | $ | 5 | $ | 27 | $ | 12 | $ | 26 | $ | 38 | ||||||||||||||||||
Regulatory required programs | 6 | — | 6 | 6 | — | 6 | 3 | 1 | 4 | |||||||||||||||||||||||||||
Transmission revenue | 8 | — | 8 | 28 | — | 28 | (1 | ) | — | (1 | ) | |||||||||||||||||||||||||
Other, net | 4 | — | 4 | 20 | (5 | ) | 15 | 3 | 1 | 4 | ||||||||||||||||||||||||||
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Total increase | $ | 34 | $ | 4 | $ | 38 | $ | 76 | $ | — | $ | 76 | $ | 17 | $ | 28 | $ | 45 | ||||||||||||||||||
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Distribution Rate Increase. The increase in distribution revenues for the three and nine months ended September 30, 2016,March 31, 2017, compared to the same periodsperiod in 2015,2016, was primarily due to the impact of the new electric and natural gas distribution rates charged to customers that became effective in June 2016 and July 2016 in accordance with the MDPSC approved electric and natural gas distribution rate case orders.orders in June 2016 and July 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Revenue Decoupling. The demand for electricity and natural gas is affected by weather and usage conditions. The MDPSC allows BGE to record a monthly adjustment to its electric and natural gas distribution revenue from all residential customers, commercial electric customers, the majority of large industrial electric customers, and all firm service natural gas customers to eliminate the effect of abnormal weather and usage patterns per customer on BGE’s electric and natural gas distribution volumes, thereby recovering a specified
dollar amount of distribution revenue per customer, by customer class, regardless of changes in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved levels per customer, regardless of what BGE’s actual distribution volumes were for a billing period. Therefore, while this revenue is affected by customer growth (i.e., increase in the number of customers), it will not be affected by actual weather or usage conditions (i.e., changes in consumption per customer). BGE bills or credits customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.
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 a30-year period in BGE’s service territory. The changes in heating and cooling degree days in BGE’s service territory for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 consisted of the following:
2016 | 2015 | Normal | % Change | 2017 | 2016 | Normal | % Change | |||||||||||||||||||||||||||||||||
Heating and Cooling Degree-Days | 2016 vs. 2015 | 2016 vs. Normal | 2017 vs. 2016 | 2017 vs. Normal | ||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||||||||||||||||
Heating Degree-Days | 24 | 46 | 79 | (47.8 | )% | (69.6 | )% | 2,063 | 2,280 | 2,404 | (9.5 | )% | (14.2 | )% | ||||||||||||||||||||||||||
Cooling Degree-Days | 747 | 592 | 594 | 26.2 | % | 25.8 | % | — | — | — | n/a | n/a | ||||||||||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||
Heating Degree-Days | 2,878 | 3,418 | 2,999 | (15.8 | )% | (4.0 | )% | |||||||||||||||||||||||||||||||||
Cooling Degree-Days | 966 | 909 | 851 | 6.3 | % | 13.5 | % |
Regulatory Required Programs. This represents the change in revenue collected under approved riders to recover costs incurred for the energy efficiency and demand response programs. The riders are designed to provide full 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 in BGE’s Consolidated Statements of Operations and Comprehensive Income.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered and other billing determinants. DuringThe transmission revenue stayed relatively consistent during the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015, the increase in transmission revenue was primarily due to increases in capital investment and operating and maintenance expense recoveries.2016. See Operating and Maintenance Expense below and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other, Net. Other net revenue, which can vary from period to period, includes commodity electric and gas revenue and other miscellaneous revenue such as service application and late payment fees; partially offset by commodity electric and gas purchased fuel and energy.
Operating and Maintenance Expense
The changes in operating and maintenance expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015,2016, consisted of the following:
Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Impairment on long-lived assets and losses on regulatory assets(a) | $ | — | $ | 52 | ||||
Storm-related costs | 1 | 19 | ||||||
Uncollectible accounts expense(b) | 4 | (4 | ) | |||||
City of Baltimore conduit fees(c) | 7 | 22 | ||||||
BSC costs(d) | (2 | ) | 8 | |||||
Other | (1 | ) | (8 | ) | ||||
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Total increase | $ | 9 | $ | 89 | ||||
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Increase (Decrease) | ||||
Storm-related costs | $ | (12 | ) | |
Uncollectible accounts expense(a) | (7 | ) | ||
City of Baltimore conduit fees | (4 | ) | ||
BSC costs | 3 | |||
Other | 1 | |||
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Total decrease | $ | (19 | ) | |
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Depreciation and Amortization
The changes in depreciation and amortization expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 consisted of the following:
Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | |||||||||||
Increase (Decrease) | Increase (Decrease) | Increase (Decrease) | ||||||||||
Depreciation expense(a) | $ | 1 | $ | 8 | $ | 4 | ||||||
Regulatory asset amortization(b) | 21 | 28 | 14 | |||||||||
Other | 1 | |||||||||||
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Total increase | $ | 22 | $ | 36 | $ | 19 | ||||||
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(a) | Depreciation expense increased due to ongoing capital expenditures. |
(b) | Regulatory asset amortization increased for the three |
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 remained relatively consistent.
Interest Expense, Net
Interest expense, net increased during the three and nine months ended September 30, 2016,March 31, 2017, compared to the same periodsperiod in 20152016 primarily due to higher outstanding debt.the issuance of Notes in August 2016.
Effective Income Tax Rate
BGE’s effective income tax rate was 39.1%39.0% and 39.3%39.5% for the three months ended September 30,March 31, 2017 and 2016, and 2015, respectively. BGE’s effective income tax rate was 36.3% and 39.9% for the nine months ended September 30, 2016 and 2015, respectively. The decrease in the effective income tax rate for the nine months ended September 30, 2016 compared to the same periods in 2015, is primarily due a lower taxable income and a cumulative adjustment to tax expense pending anticipated recovery from transmission customers. See Note 11—11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
BGE Electric Operating Statistics and Revenue Detail
Three Months Ended September 30, | % Change | Weather - Normal % Change | Nine Months Ended September 30, | % Change | Weather - Normal % Change | Three Months Ended March 31, | % Change | Weather - Normal % Change | ||||||||||||||||||||||||||||||||||||||||
Retail Deliveries to Customers | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||
Retail Deliveries(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Residential | 3,900 | 3,458 | 12.8 | % | n.m. | 9,996 | 10,266 | (2.6 | )% | n.m. | 3,127 | 3,479 | (10.1 | )% | (6.6 | )% | ||||||||||||||||||||||||||||||||
Small commercial & industrial | 877 | 788 | 11.3 | % | n.m. | 2,343 | 2,413 | (2.9 | )% | n.m. | 748 | 774 | (3.4 | )% | (3.2 | )% | ||||||||||||||||||||||||||||||||
Large commercial & industrial | 3,992 | 3,829 | 4.3 | % | n.m. | 10,627 | 10,735 | (1.0 | )% | n.m. | 3,268 | 3,219 | 1.5 | % | (1.7 | )% | ||||||||||||||||||||||||||||||||
Public authorities & electric railroads | 72 | 75 | (4.0 | )% | n.m. | 215 | 224 | (4.0 | )% | n.m. | 68 | 71 | (4.2 | )% | (4.8 | )% | ||||||||||||||||||||||||||||||||
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Total electric deliveries | 8,841 | 8,150 | 8.5 | % | n.m. | 23,181 | 23,638 | (1.9 | )% | n.m. | 7,211 | 7,543 | (4.4 | )% | (4.1 | )% | ||||||||||||||||||||||||||||||||
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As of September 30, | As of March 31, | |||||||||||||||||||||||||||||||||||||||||||||||
Number of Electric Customers | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||||
Residential | 1,145,020 | 1,132,836 | 1,153,688 | 1,141,814 | ||||||||||||||||||||||||||||||||||||||||||||
Small commercial & industrial | 112,609 | 112,888 | 113,238 | 113,034 | ||||||||||||||||||||||||||||||||||||||||||||
Large commercial & industrial | 12,030 | 11,863 | 12,084 | 11,932 | ||||||||||||||||||||||||||||||||||||||||||||
Public authorities & electric railroads | 282 | 286 | 279 | 282 | ||||||||||||||||||||||||||||||||||||||||||||
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Total | 1,269,941 | 1,257,873 | 1,279,289 | 1,267,062 | ||||||||||||||||||||||||||||||||||||||||||||
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Three Months Ended September 30, | % Change | Nine Months Ended September 30, | % Change | Three Months Ended March 31, | % Change | |||||||||||||||||||||||||||||||
Electric Revenue | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||
Retail Sales(a) | ||||||||||||||||||||||||||||||||||||
Residential | $ | 451 | $ | 379 | 19.0 | % | $ | 1,203 | $ | 1,131 | 6.4 | % | $ | 405 | $ | 428 | (5.4 | )% | ||||||||||||||||||
Small commercial & industrial | 74 | 70 | 5.7 | % | 212 | 208 | 1.9 | % | 72 | 73 | (1.4 | )% | ||||||||||||||||||||||||
Large commercial & industrial | 123 | 122 | 0.8 | % | 337 | 351 | (4.0 | )% | 113 | 100 | 13.0 | % | ||||||||||||||||||||||||
Public authorities & electric railroads | 9 | 9 | — | % | 27 | 24 | 12.5 | % | 7 | 9 | (22.2 | )% | ||||||||||||||||||||||||
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Total retail | 657 | 580 | 13.3 | % | 1,779 | 1,714 | 3.8 | % | 597 | 610 | (2.1 | )% | ||||||||||||||||||||||||
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Other revenue(b) | 78 | 75 | 4.0 | % | 219 | 194 | 12.9 | % | 70 | 70 | — | % | ||||||||||||||||||||||||
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Total electric revenue | $ | 735 | $ | 655 | 12.2 | % | $ | 1,998 | $ | 1,908 | 4.7 | % | $ | 667 | $ | 680 | (1.9 | )% | ||||||||||||||||||
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(a) | Reflects delivery volumes and revenue from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission. |
(b) | Includes operating revenues from affiliates totaling |
BGE Natural Gas Operating Statistics and Revenue Detail
Three Months Ended September 30, | % Change | Weather - Normal % Change | Nine Months Ended September 30, | % Change | Weather - Normal % Change | Three Months Ended March 31, | % Change | Weather - Normal % Change | ||||||||||||||||||||||||||||||||||||||||
Deliveries to Customers (in mmcf) | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||
Retail Deliveries(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Retail sales | 13,159 | 11,719 | 12.3 | % | n.m. | 69,415 | 72,481 | (4.2 | )% | n.m. | 36,371 | 38,584 | (5.7 | )% | 2.3 | % | ||||||||||||||||||||||||||||||||
Transportation and other(b) | 1,311 | 612 | 114.2 | % | n.m. | 4,078 | 4,521 | (9.8 | )% | n.m. | 2,279 | 2,496 | (8.7 | )% | n/a | |||||||||||||||||||||||||||||||||
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Total natural gas deliveries | 14,470 | 12,331 | 17.3 | % | n.m. | 73,493 | 77,002 | (4.6 | )% | n.m. | 38,650 | 41,080 | (5.9 | )% | 2.3 | % | ||||||||||||||||||||||||||||||||
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As of September 30, | As of March 31, | |||||||||||||||||||||||||||||||||||||||||||||||
Number of Gas Customers | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||||
Residential | 619,837 | 613,571 | 625,642 | 619,130 | ||||||||||||||||||||||||||||||||||||||||||||
Commercial & industrial | 43,957 | 43,885 | 44,237 | 44,224 | ||||||||||||||||||||||||||||||||||||||||||||
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Total | 663,794 | 657,456 | 669,879 | 663,354 | ||||||||||||||||||||||||||||||||||||||||||||
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Three Months Ended September 30, | % Change | Nine Months Ended September 30, | % Change | Three Months Ended March 31, | % Change | |||||||||||||||||||||||||||||||
Natural Gas Revenue | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||
Retail Sales(a) | ||||||||||||||||||||||||||||||||||||
Retail sales | $ | 71 | $ | 66 | 7.6 | % | $ | 403 | $ | 450 | (10.4 | )% | $ | 269 | $ | 238 | 13.0 | % | ||||||||||||||||||
Transportation and other(b) | 6 | 4 | 50.0 | % | 20 | 30 | (33.3 | )% | 15 | 11 | 36.4 | % | ||||||||||||||||||||||||
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Total natural gas revenues(c) | $ | 77 | $ | 70 | 10.0 | % | $ | 423 | $ | 480 | (11.9 | )% | $ | 284 | $ | 249 | 14.1 | % | ||||||||||||||||||
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(a) | Reflects delivery volumes and revenue from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. The cost of natural gas is charged to customers purchasing natural gas from BGE. |
(b) | Transportation and other gas revenue includesoff-system revenue of |
(c) | Includes operating revenues from affiliates totaling |
PHI’s results of operations include the results of its three reportable segments, Pepco, DPL and ACE for all periods presented below. For “Predecessor” reporting periods, PHI’s results of operations also include the results of PES and PCI. See Note 2019 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding PHI’s reportable segments. All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific discussion of the results of operations for Pepco, DPL and ACE is presented elsewhere in this report.
As a result of the PHI Merger, the following consolidated financial results present two separate reporting periods for 2016. The “Predecessor” reporting periods representperiod represents PHI’s results of operations for the three and nine months ended September 30, 2015 and for the period from January 1, 2016 to March 23, 2016. The “Successor” reporting periods represent PHI’s results of operations for the three months ended September 30, 2016March 31, 2017 and for the period from March 24, 2016 to September 30,March 31, 2016. All amounts presented below are before the impact of income taxes, except as noted.
Successor | Predecessor | Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||
Three Months Ended September 30, 2016 | Three Months Ended September 30, 2015 | March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | Nine Months Ended September 30, 2015 | Three Months Ended March 31, 2017 | March 24 to March 31, 2016 | January 1 to March 23, 2016 | |||||||||||||||||||||||||
Operating revenues | $ | 1,394 | $ | 1,336 | $ | 2,565 | $ | 1,153 | $ | 3,809 | $ | 1,175 | $ | 105 | $ | 1,153 | ||||||||||||||||
Purchased power and fuel | 583 | 579 | 1,037 | 497 | 1,646 | |||||||||||||||||||||||||||
Purchased power and fuel expense | 461 | 38 | 497 | |||||||||||||||||||||||||||||
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Revenue net of purchased power and fuel(a) | 811 | 757 | 1,528 | 656 | 2,163 | |||||||||||||||||||||||||||
Revenue net of purchased power and fuel expense(a) | 714 | 67 | 656 | |||||||||||||||||||||||||||||
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Other operating expenses | ||||||||||||||||||||||||||||||||
Operating and maintenance | 226 | 287 | 921 | 294 | 875 | 256 | 449 | 294 | ||||||||||||||||||||||||
Depreciation and amortization | 182 | 166 | 355 | 152 | 474 | 167 | 14 | 152 | ||||||||||||||||||||||||
Taxes other than income | 124 | 120 | 248 | 105 | 349 | 111 | 15 | 105 | ||||||||||||||||||||||||
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Total other operating expenses | 532 | 573 | 1,524 | 551 | 1,698 | 534 | 478 | 551 | ||||||||||||||||||||||||
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Operating income | 279 | 184 | 4 | 105 | 465 | |||||||||||||||||||||||||||
Operating income (loss) | 180 | (411 | ) | 105 | ||||||||||||||||||||||||||||
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Other income and (deductions) | ||||||||||||||||||||||||||||||||
Interest expense, net | (64 | ) | (71 | ) | (135 | ) | (65 | ) | (211 | ) | (62 | ) | (6 | ) | (65 | ) | ||||||||||||||||
Other, net | 19 | 27 | 31 | (4 | ) | 48 | 13 | 2 | (4 | ) | ||||||||||||||||||||||
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Total other income and (deductions) | (45 | ) | (44 | ) | (104 | ) | (69 | ) | (163 | ) | (49 | ) | (4 | ) | (69 | ) | ||||||||||||||||
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Income (loss) before income taxes | 234 | 140 | (100 | ) | 36 | 302 | 131 | (415 | ) | 36 | ||||||||||||||||||||||
Income taxes | 68 | 49 | (9 | ) | 17 | 105 | (9 | ) | (106 | ) | 17 | |||||||||||||||||||||
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Net income (loss) attributable to membership interest/common shareholders | $ | 166 | $ | 91 | $ | (91 | ) | $ | 19 | $ | 197 | |||||||||||||||||||||
Net income (loss) | $ | 140 | $ | (309 | ) | $ | 19 | |||||||||||||||||||||||||
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(a) | PHI evaluates its operating performance using the measure of revenue net of purchased power and fuel expense for electric and natural gas sales. PHI believes revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. PHI has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power and fuel expense 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. |
Successor Period Three Months Ended September 30, 2016March 31, 2017
PHI’s net income attributable to common shareholders for the Successor period of three months ended September 30, 2016March 31, 2017 was $166$140 million. Therewere no significant changes in the underlying trends affecting
PHI’s operations during the Successor period of three months ended September 30, 2016March 31, 2017 except for the pre-tax recordingimpact of a $50 million reduction of merger-related commitmentsincreases in electric distribution and natural gas rates within Operating and maintenance expense reflecting a reallocation of the most favored nation commitments among Exelon and Pepco, DPL and ACE, such that more commitments are expected to be obligations of Exelon for energy efficiency, workforce development and other programs as opposed to obligations of Pepco, DPL and ACE for additional customer rate credits.
Successor Period Three Months Ended September 30, 2016 Compared to the Predecessor Period Three Months Ended September 30, 2015
Net Income Attributable to Common Shareholders
PHI’s net income attributable to common shareholders was $166 million for the three months ended September 30, 2016 as compared to $91 million for the three months ended September 30, 2015.
Operating Revenue Net of Purchased Power and Fuel Expense
Operating revenue net of purchased power expense (Pepco electric distribution rates effective November 2016 in Maryland, DPL electric distribution rates effective February 2017 in Maryland, DPL electric distribution and fuelnatural gas rates effective July 2016 and December 2016 in Delaware, and ACE electric distribution rates
effective August 2016 in New Jersey). Lower uncollectible accounts expense which isand the deferral of merger-related costs to a non-GAAP measure discussed above, increased by $54regulatory asset contributed to lower Operating and maintenance expense. Income taxes were lower due to unrecognized tax benefits of $59 million for the three months ended September 30, 2016 as compared to the three months ended September 30, 2015. The increase is attributable to the following factors:
Increase of $30 million at Pepco primarily related to electric distribution revenue increases totaling $9 million due to customer growth, $18 million in required regulatory programs primarily due to an EmPower Maryland rate increase effective February 2015, and $3 million higher transmission revenue due to a higher rate effective June 1, 2015 and due to the establishment of reserves recorded in September 2015uncertain tax positions related to the FERC ROE challenges, partially offset by lower revenue related to the MAPP abandonment recovery period ending March 2016;
Increasedeductibility of $18 million at DPL primarily related to electric distribution revenue increases totaling $7 million due to customer growth and higher weather-related sales, an increase of $6 million due to an EmPower Maryland rate increase effective February 2015, and $5 million higher transmission revenue due to a higher rate effective June 1, 2015 and due to the establishment of a reserve recorded in September 2015 related to the FERC ROE challenges, partially offset by lower revenue related to the MAPP abandonment recovery period ending March 2016;
Increase of $28 million at ACE primarily related to electric distribution revenue increases totaling $17 million due to higher average customer usage and a rate increase effective August 2016 and $11 million higher transmission revenue due to a higher rate effective June 1, 2015 and due to the establishment of a reserve recorded in September 2015 related to the FERC ROE challenges;
Increase of $13 million due to the effects of a decrease in ACE’s BGS unbilled revenue resulting from lower average customer usage in the third quarter 2015;
Increase of $11 million at Corporate primarily due to BSC inter-company transactions; and
Decrease of $46 million at PES due to PHI’s results of operations including the results of PES in 2015 and not in 2016.
Operating and Maintenance Expense
Operating and maintenance expense decreased by $61 million for the three months ended September 30, 2016 as compared to the three months ended September 30, 2015. The decrease is attributable to the following factors:
Decrease of $27 million at Pepco, DPL and ACE primarily due to a $50 million reduction of merger-related commitments reflecting a reallocation of the most favored nation commitments among Exelon and Pepco, DPL and ACE, such that more commitments are expected to be obligations of Exelon for
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Increase of $12 million at Corporate primarily due to BSC inter-company and purchase accounting transactions; and
Decrease of $46 million at PES due to PHI’s results of operations including the results of PES in 2015 and not in 2016.
Depreciation and Amortization Expense
Depreciation and amortization expense increased by $16 million primarily due to $8 million higher amortization of regulatory assets due to an EmPower Maryland surcharge rate increase effective February 2015, partially offset by lower amortization of MAPP abandonment costs, and higher depreciation of $6 million due to ongoing capital expenditures at Pepco, DPL, and ACE.
Taxes Other Than Income
Taxes other than income increased by $4 million primarily due to higher utility taxes that are collected and passed through by Pepco and DPL.
Interest Expense, Net
Interest expense decreased by $7 million primarily due to purchase accounting entries related to the fair value of long-term debt.
Other, Net
Other, net for the three months ended September 30, 2016 decreased by $8 million due to $15 million of income recorded in September 2015 from a change in the fair value of the derivative related to preferred stock, partially offset by higher AFUDC income in 2016.
Effective Income Tax Ratecertain merger commitments.
PHI’s effective income tax ratesrate for the Successor period of three months ended September 30, 2016 and 2015 were 29.1% and 35.0%, respectively.March 31, 2017 was (6.9)%. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Successor Period March 24, 2016 to September 30,March 31, 2016
PHI’s net loss attributable to common shareholders for the Successor period offrom March 24, 2016 to September 30,March 31, 2016was $(91)$309 million. Therewere no significant changes in the underlying trends affecting PHI’s results of operations during the Successor period of March 24, 2016 to September 30,March 31, 2016 except for thepre-tax recording of $375$419 million ofnon-recurring merger-related costs within Operating and maintenance expense.
PHI’s effective income tax rate for the Successor period of March 24, 2016 to September 30,March 31, 2016 was 9.0%25.5%. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Predecessor Period January 1, 2016 to March 23, 2016
PHI’s net income attributable to common shareholders for the Predecessor period of January 1, 2016 to March 23, 2016was $19 million. Therewere no significant changes in the underlying trends affecting PHI’s
results of operations during the Predecessor period of January 1, 2016 to March 23, 2016 except for thepre-tax recording of $29 million ofnon-recurring merger-related costs within Operating and maintenance expense and $18 million of preferred stock derivative expense within Other, net.
PHI’s effective income tax rate for the Predecessor period of January 1, 2016 to March 23, 2016 was 47.2%. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Predecessor Period January 1, 2015 to September 30, 2015
PHI’s net income attributable to common shareholders for the Predecessor period of the nine months ended September 30, 2015 was $197 million. There were no significant changes in the underlying trends affecting PHI’s operations during the Predecessor period of the nine months ended September 30, 2015 except for the pre-tax recording of $37 million of implementation and support costs due to the completion of a new customer information system and $16 million of non-recurring merger-related costs within Operating and maintenance expense and $15 million of income due to a change in the fair value of the derivative related to preferred stock within Other, net.
PHI’s effective income tax rate for the nine months ended September 30, 2015 was 34.8%. See Note 11—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Three Months Ended September 30, | Favorable (Unfavorable) Variance | Nine Months Ended September 30, | Favorable (Unfavorable) Variance | Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||||||||||||
Operating revenues | $ | 635 | $ | 592 | $ | 43 | $ | 1,695 | $ | 1,641 | $ | 54 | $ | 530 | $ | 551 | $ | (21 | ) | |||||||||||||||||
Purchased power expense | 213 | 200 | (13 | ) | 563 | 573 | 10 | 166 | 197 | 31 | ||||||||||||||||||||||||||
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Revenue net of purchased power expense(a) | 422 | 392 | 30 | 1,132 | 1,068 | 64 | 364 | 354 | 10 | |||||||||||||||||||||||||||
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Other operating expenses | ||||||||||||||||||||||||||||||||||||
Operating and maintenance | 109 | 111 | 2 | 508 | 327 | (181 | ) | 113 | 290 | 177 | ||||||||||||||||||||||||||
Depreciation and amortization | 76 | 66 | (10 | ) | 221 | 191 | (30 | ) | 82 | 75 | (7 | ) | ||||||||||||||||||||||||
Taxes other than income | 105 | 100 | (5 | ) | 287 | 289 | 2 | 90 | 94 | 4 | ||||||||||||||||||||||||||
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Total other operating expenses | 290 | 277 | (13 | ) | 1,016 | 807 | (209 | ) | 285 | 459 | 174 | |||||||||||||||||||||||||
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Gain on sale of assets | — | — | — | 8 | — | 8 | ||||||||||||||||||||||||||||||
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Operating income | 132 | 115 | 17 | 124 | 261 | (137 | ) | |||||||||||||||||||||||||||||
Operating income (loss) | 79 | (105 | ) | 184 | ||||||||||||||||||||||||||||||||
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Other income and (deductions) | ||||||||||||||||||||||||||||||||||||
Interest expense, net | (30 | ) | (31 | ) | 1 | (98 | ) | (92 | ) | (6 | ) | (29 | ) | (37 | ) | 8 | ||||||||||||||||||||
Other, net | 12 | 8 | 4 | 28 | 21 | 7 | 8 | 9 | (1 | ) | ||||||||||||||||||||||||||
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Total other income and (deductions) | (18 | ) | (23 | ) | 5 | (70 | ) | (71 | ) | 1 | (21 | ) | (28 | ) | 7 | |||||||||||||||||||||
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Income before income taxes | 114 | 92 | 22 | 54 | 190 | (136 | ) | |||||||||||||||||||||||||||||
Income (loss) before income taxes | 58 | (133 | ) | 191 | ||||||||||||||||||||||||||||||||
Income taxes | 35 | 32 | (3 | ) | 34 | 62 | 28 | — | (25 | ) | (25 | ) | ||||||||||||||||||||||||
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Net income attributable to common shareholder | $ | 79 | $ | 60 | $ | 19 | $ | 20 | $ | 128 | $ | (108 | ) | |||||||||||||||||||||||
Net income (loss) | $ | 58 | $ | (108 | ) | $ | 166 | |||||||||||||||||||||||||||||
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(a) | Pepco evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. Pepco believes revenue net of purchased power expense is a useful measurement because it provides information |
that can be used to evaluate its operational performance. Pepco has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense 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. |
Net Income Attributable to Common Shareholder(Loss)
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015. March 31, 2016.Pepco’s net income attributable to common shareholder for the three months ended September 30, 2016,March 31, 2017, was higher than the same period in 2015,2016, primarily due to an increase in revenue net of purchased power expense resulting from customer growth and and due tohigher electric distribution revenues as a decrease in operating and maintenance expense reflecting a revision in the estimate of Pepco’s merger commitment costs associated with the most favored nation provisionresult of the merger orders. The revisiondistribution rate orders issued by the MDPSC in estimate included a reduction in Pepco’s merger commitment costs of $13 million, reflecting a reallocation of the most favored nation commitments among Exelon and Pepco, such that more commitments are expected to be obligations of Exelon for energy efficiency and other programs as opposed to obligations of Pepco for additional customer rate credits.
Nine Months Ended September 30,November 2016, Compared to Nine Months Ended September 30, 2015. Pepco’s net income attributable to common shareholder for the nine months ended September 30, 2016, was lower than the same period in 2015, primarily due to an increase in operatingOperating and maintenance expense due to merger-related costs.costs recognized in March 2016 and lower uncollectible accounts expense, and a decrease in income tax reserves for uncertain tax positions related to the deductibility of certain merger commitments.
Operating Revenue Net of Purchased Power Expense
Operating revenues include revenue from the distribution and supply of electricity to Pepco’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that Pepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All Pepco customers have the choice to purchase electricity from competitive electric generation suppliers. The customers’ choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and nine months ended September 30, 2016,March 31, 2017, compared to the same periodsperiod in 2015,2016, consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Electric | 63 | % | 65 | % | 65 | % | 64 | % |
Three Months Ended March 31, | ||||||||
2017 | 2016 | |||||||
Electric | 64 | % | 65 | % |
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30,March 31, 2017 and 2016 and 2015 consisted of the following:
September 30, 2016 | September 30, 2015 | |||||||||||||||
Number of customers | % of total retail customers | Number of customers | % of total retail customers | |||||||||||||
Electric | 175,960 | 21 | % | 158,601 | 19 | % |
March 31, 2017 | March 31, 2016 | |||||||||||||||
Number of customers | % of total retail customers | Number of customers | % of total retail customers | |||||||||||||
Electric | 179,241 | 21 | % | 173,221 | 21 | % |
Retail deliveries purchased from competitive electric generation suppliers represented 71% and 72%73% of Pepco’s retail kWh sales to the District of Columbia customers and 58% and 59% of Pepco’s retail kWh sales to
Maryland customers for the three and nine months ended September 30, 2016March 31, 2017 and 71% and 70%73% of Pepco’s retail kWh sales to the District of Columbia customers and 61% and 59%58% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2015.March 31, 2016.
The costs related to default electricity supply are included in Purchased power expense.
Operating revenues also include transmission enhancement credits that Pepco receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.
Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Purchased power expense consists of the cost of electricity purchased by Pepco to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders.
The changes in Pepco’s operating revenues net of purchased power expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same period in 20152016 consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
Increase (Decrease) | Increase (Decrease) | Increase (Decrease) | ||||||||||
Volume | $ | 8 | $ | 22 | $ | 4 | ||||||
Pricing — distribution revenues | 16 | |||||||||||
Regulatory required programs | 18 | 36 | (10 | ) | ||||||||
Transmission revenue | 3 | 3 | ||||||||||
Transmission revenues | 2 | |||||||||||
Other | 1 | 3 | (2 | ) | ||||||||
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Total increase | $ | 30 | $ | 64 | $ | 10 | ||||||
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Revenue Decoupling. Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco in Maryland and in the District of Columbia, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.
In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer.
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 a20-year period in Pepco’s service territory. The changes in heating and cooling degree days in Pepco’s service territory for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 and normal weather consisted of the following:
% Change | % Change | |||||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, | 2016 | 2015 | Normal | 2016 vs. 2015 | 2016 vs. Normal | |||||||||||||||||||||||||||||||||||
2017 | 2016 | Normal | 2017 vs. 2016 | 2017 vs. Normal | ||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||||||||||||||||
Heating Degree-Days | 1 | — | 13 | — | % | (92.3 | )% | 1,748 | 2,010 | 2,138 | (13.0 | )% | (18.2 | )% | ||||||||||||||||||||||||||
Cooling Degree-Days | 1,418 | 1,239 | 1,109 | 14.4 | % | 27.9 | % | 4 | 3 | 3 | 33.3 | % | 33.3 | % | ||||||||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||
Heating Degree-Days | 2,408 | 2,691 | 2,507 | (10.5 | )% | (3.9 | )% | |||||||||||||||||||||||||||||||||
Cooling Degree-Days | 1,872 | 1,914 | 1,587 | (2.2 | )% | 18.0 | % |
Volume. The increase in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015,2016, primarily reflects the impact of moderate economic and customer growth.
Pricing — Distribution Revenues. The increase in electric operating revenues net of purchased power expense as a result of pricing for the three months ended March 31, 2017 compared to the same period in 2016 was primarily due to the impact of the new electric distribution rates charged to customers in Maryland that became effective in November 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs.This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and other taxes. Refer to the operating and maintenance expense discussion below for additional information on included programs.
Transmission Revenue.Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered and other billing adjustments. The increase in revenue net of purchased power expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 is a result of higher rates effective June 1, 20152016 related to increases in transmission plant investment and operating expenses, and due to the establishment of a reserve recorded in September 2015 related to the FERC ROE challenges, partially offset by lower revenue related to the MAPP abandonment recovery period that ended in March 2016.
Operating and Maintenance Expense
Three Months Ended September 30, | Increase (Decrease) | Nine Months Ended September 30, | Increase (Decrease) | Three Months Ended March 31, | Increase (Decrease) | |||||||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||||||||||||
Operating and maintenance expense — baseline | $ | 106 | $ | 107 | $ | (1 | ) | $ | 500 | $ | 318 | $ | 182 | $ | 114 | $ | 287 | $ | (173 | ) | ||||||||||||||||
Operating and maintenance expense — regulatory required programs(a) | 3 | 4 | (1 | ) | 8 | 9 | (1 | ) | (1 | ) | 3 | (4 | ) | |||||||||||||||||||||||
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Total operating and maintenance expense | $ | 109 | $ | 111 | $ | (2 | ) | $ | 508 | $ | 327 | $ | 181 | $ | 113 | $ | 290 | $ | (177 | ) | ||||||||||||||||
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(a) | Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues. |
The changes in operating and maintenance expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015,2016, consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
Increase (Decrease) | Increase (Decrease) | Increase (Decrease) | ||||||||||
Baseline | ||||||||||||
Labor, other benefits, contracting and materials | $ | 1 | $ | 6 | $ | 5 | ||||||
Storm-related costs | 2 | 5 | 1 | |||||||||
Remeasurement of AMI-related regulatory asset | 4 | 11 | ||||||||||
Uncollectible accounts expense | (9 | ) | ||||||||||
Deferral of merger-related costs to regulatory asset | (1 | ) | (10 | ) | (1 | ) | ||||||
BSC and PHISCO allocations(a) | 6 | 41 | (27 | ) | ||||||||
Merger commitments(b) | (13 | ) | 126 | (139 | ) | |||||||
Other | — | 3 | (3 | ) | ||||||||
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(1 | ) | 182 | (173 | ) | ||||||||
Regulatory required programs | ||||||||||||
Purchased power administrative costs | (1 | ) | (1 | ) | (4 | ) | ||||||
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Total decrease | $ | (177 | ) | |||||||||
(1 | ) | (1 | ) |
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Total (decrease) increase | $ | (2 | ) | $ | 181 | |||||||
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(a) | Primarily related to merger severance and compensation |
(b) | Primarily related to merger-related commitments for customer rate credits |
Depreciation and Amortization Expense
The changes in depreciation and amortization expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015,2016, consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
Increase (Decrease) | Increase (Decrease) | Increase (Decrease) | ||||||||||
Depreciation expense(a) | $ | 2 | $ | 6 | $ | 8 | ||||||
Regulatory asset amortization(b) | 8 | 24 | ||||||||||
Regulatory asset amortization | (1 | ) | ||||||||||
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Total increase | $ | 10 | $ | 30 | $ | 7 | ||||||
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(a) | Depreciation expense increased due to higher depreciation rates in Maryland effective November 2016 and due to ongoing capital expenditures. |
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Taxes Other Than Income
Taxes other than income for the three months ended September 30, 2016March 31, 2017 compared to the same period in 2015 increased2016 decreased primarily due to higherlower utility taxes that are collected and passed through by Pepco. Taxes other than income for the nine months ended September 30, 2016 compared to the same period in 2015 decreased primarily due to lower property taxes in MarylandPepco, partially offset by higher utilityproperty taxes that are collected and passed through by Pepco.
Gain on Sale of Assets
Gain on sale of assets for the nine months ended September 30, 2016 compared to the same period in 2015 increased due to a second quarter 2016 gain recorded from the sale of land.Maryland.
Interest Expense, Net
Interest expense, net for the ninethree months ended September 30, 2016March 31, 2017 compared to the same period in 2015 increased $6 million2016 decreased primarily due to the recording of interest expense for an uncertain tax position in the first quarter of 2016.2016 and an increase in capitalized AFUDC interest.
Other, Net
Other, net for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015 increased primarily due to higher income from AFUDC.2016 remained relatively constant.
Effective Income Tax Rate
Pepco’s effective income tax rate was 30.7%0.0% and 34.8%18.8% for the three months ended September 30,March 31, 2017 and 2016, respectively. In the first quarter of 2017, Pepco decreased its liability for unrecognized tax benefits by $21 million resulting in a benefit to Income taxes and 2015, respectively. Pepco’sa corresponding decrease in its effective income tax rate was 63.0% and 32.6% for the nine months ended September 30, 2016 and 2015, respectively.rate. See Note 11 — 11—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates. As a result of the merger, Pepco recorded an after-tax charge of $30 million during the nine months ended September 30, 2016 as a result of the assessment and remeasurement of certain federal and state uncertain tax positions.
Pepco Electric Operating Statistics and Revenue Detail
Three Months Ended September 30, | % Change | Weather - Normal % Change | Nine Months Ended September 30, | % Change | Weather - Normal % Change | Three Months Ended March 31, | ||||||||||||||||||||||||||||||||||||||||||
Retail Deliveries to Customers (in GWhs) | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | % Change | Weather - Normal % Change | ||||||||||||||||||||||||||||||||||||||||
Retail Deliveries(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Residential | 2,675 | 2,355 | 13.6 | % | 11.0 | % | 6,652 | 6,844 | (2.8 | )% | 3.1 | % | 2,000 | 2,218 | (9.8 | )% | (4.4 | )% | ||||||||||||||||||||||||||||||
Small commercial & industrial | 394 | 379 | 4.0 | % | 5.3 | % | 1,124 | 1,150 | (2.3 | )% | 1.4 | % | 326 | 381 | (14.4 | )% | (12.4 | )% | ||||||||||||||||||||||||||||||
Large commercial & industrial | 4,314 | 4,254 | 1.4 | % | 4.8 | % | 11,890 | 11,759 | 1.1 | % | 1.4 | % | 3,485 | 3,945 | (11.7 | )% | (10.8 | )% | ||||||||||||||||||||||||||||||
Public authorities & electric railroads | 180 | 177 | 1.7 | % | 1.1 | % | 544 | 540 | 0.7 | % | — | % | 190 | 189 | 0.5 | % | 0.5 | % | ||||||||||||||||||||||||||||||
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Total retail deliveries | 7,563 | 7,165 | 5.6 | % | 6.9 | % | 20,210 | 20,293 | (0.4 | )% | 1.9 | % | 6,001 | 6,733 | (10.9 | )% | (8.4 | )% | ||||||||||||||||||||||||||||||
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As of September 30, | As of March 31, | |||||||||||||||||||||||||||||||||||||||||||||||
Number of Electric Customers | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||||
Residential | 775,911 | 749,662 | 785,016 | 769,934 | ||||||||||||||||||||||||||||||||||||||||||||
Small commercial & industrial | 53,425 | 53,459 | 53,640 | 53,853 | ||||||||||||||||||||||||||||||||||||||||||||
Large commercial & industrial | 21,315 | 20,820 | 21,413 | 20,996 | ||||||||||||||||||||||||||||||||||||||||||||
Public authorities & electric railroads | 129 | 128 | 136 | 126 | ||||||||||||||||||||||||||||||||||||||||||||
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Total | 850,780 | 824,069 | 860,205 | 844,909 | ||||||||||||||||||||||||||||||||||||||||||||
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Three Months Ended September 30, | % Change | Nine Months Ended September 30, | % Change | Three Months Ended March 31, | ||||||||||||||||||||||||||||||||||||||||||||
Electric Revenue | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | % Change | |||||||||||||||||||||||||||||||||||||||||
Retail Sales(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Residential | $ | 315 | $ | 285 | 10.5 | % | $ | 791 | $ | 769 | 2.9 | % | $ | 240 | $ | 255 | (5.9 | )% | ||||||||||||||||||||||||||||||
Small commercial & industrial | 43 | 43 | — | % | 116 | 116 | — | % | 34 | 37 | (8.1 | )% | ||||||||||||||||||||||||||||||||||||
Large commercial & industrial | 219 | 210 | 4.3 | % | 613 | 590 | 3.9 | % | 195 | 200 | (2.5 | )% | ||||||||||||||||||||||||||||||||||||
Public authorities & electric railroads | 7 | 7 | — | % | 23 | 23 | — | % | 8 | 8 | — | % | ||||||||||||||||||||||||||||||||||||
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Total retail | 584 | 545 | 7.2 | % | 1,543 | 1,498 | 3.0 | % | 477 | 500 | (4.6 | )% | ||||||||||||||||||||||||||||||||||||
Other revenue(b) | 51 | 47 | 8.5 | % | 152 | 143 | 6.3 | % | 53 | 51 | 3.9 | % | ||||||||||||||||||||||||||||||||||||
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Total electric revenue(c) | $ | 635 | $ | 592 | 7.3 | % | $ | 1,695 | $ | 1,641 | 3.3 | % | $ | 530 | $ | 551 | (3.8 | )% | ||||||||||||||||||||||||||||||
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(a) | Reflects delivery volumes and revenues from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from Pepco, revenue also reflects the cost of energy and transmission. |
(b) | Other revenue includes transmission revenue from PJM and wholesale electric revenues. |
(c) | Includes operating revenues from affiliates totaling $1 million and $1 million for the three months ended |
Three Months Ended September 30, | Favorable (Unfavorable) Variance | Nine Months Ended September 30, | Favorable (Unfavorable) Variance | Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||||||||||||
Operating revenues | $ | 331 | $ | 314 | $ | 17 | $ | 974 | $ | 1,004 | $ | (30 | ) | $ | 362 | $ | 362 | $ | — | |||||||||||||||||
Purchased power and fuel | 150 | 151 | 1 | 448 | 500 | 52 | ||||||||||||||||||||||||||||||
Purchased power and fuel expense | 157 | 176 | 19 | |||||||||||||||||||||||||||||||||
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Revenue net of purchased power and fuel(a) | 181 | 163 | 18 | 526 | 504 | 22 | ||||||||||||||||||||||||||||||
Revenues net of purchased power and fuel expense(a) | 205 | 186 | 19 | |||||||||||||||||||||||||||||||||
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Other operating expenses | ||||||||||||||||||||||||||||||||||||
Operating and maintenance | 55 | 77 | 22 | 338 | 234 | (104 | ) | 73 | 204 | 131 | ||||||||||||||||||||||||||
Depreciation, amortization and accretion | 44 | 40 | (4 | ) | 120 | 113 | (7 | ) | ||||||||||||||||||||||||||||
Depreciation and amortization | 39 | 39 | — | |||||||||||||||||||||||||||||||||
Taxes other than income | 14 | 14 | — | 42 | 39 | (3 | ) | 15 | 15 | — | ||||||||||||||||||||||||||
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Total other operating expenses | 113 | 131 | 18 | 500 | 386 | (114 | ) | 127 | 258 | 131 | ||||||||||||||||||||||||||
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Gain on sale of asset | 4 | — | 4 | 4 | — | 4 | ||||||||||||||||||||||||||||||
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Operating income | 72 | 32 | 40 | 30 | 118 | (88 | ) | |||||||||||||||||||||||||||||
Operating income (loss) | 78 | (72 | ) | 150 | ||||||||||||||||||||||||||||||||
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Other income and (deductions) | ||||||||||||||||||||||||||||||||||||
Interest expense, net | (12 | ) | (12 | ) | — | (37 | ) | (37 | ) | — | (13 | ) | (12 | ) | (1 | ) | ||||||||||||||||||||
Other, net | 3 | 4 | (1 | ) | 9 | 8 | 1 | 3 | 3 | — | ||||||||||||||||||||||||||
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Total other income and (deductions) | (9 | ) | (8 | ) | (1 | ) | (28 | ) | (29 | ) | 1 | (10 | ) | (9 | ) | (1 | ) | |||||||||||||||||||
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Income before income taxes | 63 | 24 | 39 | 2 | 89 | (87 | ) | |||||||||||||||||||||||||||||
Income (loss) before income taxes | 68 | (81 | ) | 149 | ||||||||||||||||||||||||||||||||
Income taxes | 19 | 9 | (10 | ) | 18 | 34 | 16 | 11 | (9 | ) | (20 | ) | ||||||||||||||||||||||||
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Net income (loss) attributable to common shareholder | $ | 44 | $ | 15 | $ | 29 | $ | (16 | ) | $ | 55 | $ | (71 | ) | ||||||||||||||||||||||
Net income (loss) | $ | 57 | $ | (72 | ) | $ | 129 | |||||||||||||||||||||||||||||
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(a) | DPL evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales and revenue net of fuel expense for natural gas sales. DPL believes revenue net of purchased power expense and revenue |
net of fuel expense are useful measurements because they provide information that can be used to evaluate its operational performance. DPL has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense and Revenue net of fuel expense 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. |
Net Income (Loss) Attributable to Common Shareholder
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.March 31, 2016. DPL’s net income attributable to common shareholder for the three months ended September 30, 2016,March 31, 2017, was higher than the same period in 20152016 as a result of an increase in revenue net of purchased power and fuel expense primarily resulting from customer growthhigher electric distribution and higher transmission revenue and due tonatural gas revenues as a decrease in operating and maintenance expense reflecting a revision in the estimate of DPL’s merger commitment costs associated with the most favored nation provisionresult of the merger orders. The revisiondistribution rate orders issued by the DPSC in estimate included a reductionJuly 2016 and December 2016 and by the MDPSC in DPL’s merger commitment costs of $27 million, reflecting a reallocation of the most favored nation commitments among Exelon and DPL, such that more commitments are expected to be obligations of Exelon for energy efficiency and other programs as opposed to obligations of DPL for additional customer rate credits.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. DPL’s net loss attributable to common shareholder for the nine months ended September 30, 2016, compared unfavorably to DPL’s net income for the same period in 2015, primarily due to an increase in operatingFebruary 2017, lower Operating and maintenance expense due to merger-related costs.costs recognized in March 2016, lower uncollectible accounts expense, and the deferral of merger-related costs to a regulatory asset in 2017, and a decrease in income tax reserves for uncertain tax positions related to the deductibility of certain merger commitments.
Operating RevenueRevenues Net of Purchased Power and Fuel Expense
Operating revenues include revenue from the distribution and supply of electricity to DPL’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
Electric and natural gas revenues and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All DPL customers have the choice to purchase electricity and
natural gas from competitive electric generation and natural gas suppliers, respectively. The customers’ choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30,March 31, 2017 and 2016, and 2015, consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, | ||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||
Electric | 49 | % | 52 | % | 51 | % | 50 | % | 50 | % | 49 | % | ||||||||||||
Natural Gas | 51 | % | 51 | % | 32 | % | 31 | % | 27 | % | 25 | % |
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30,March 31, 2017 and 2016 and 2015 consisted of the following:
September 30, 2016 | September 30, 2015 | |||||||||||||||
Number of customers | % of total retail customers | Number of customers | % of total retail customers | |||||||||||||
Electric | 79,501 | 15.4 | % | 78,545 | 15.3 | % | ||||||||||
Natural Gas | 157 | 0.1 | % | 159 | 0.1 | % |
Electric Natural Gas March 31, 2017 March 31, 2016 Number of
customers % of total retail
customers Number of
customers % of total retail
customers 79,270 15 % 77,014 15 % 156 0.1 % 158 0.1 %
Retail deliveries purchased from competitive electric generation suppliers represented 51% and 53% of DPL’s retail kWh sales to Delaware customers and 47% and 47%45% of DPL retail kWh sales to Maryland customers for the three and nine months ended September 30, 2016March 31, 2017 and 54% and 51% and to Delaware customers and 49% and 46% and44% to Maryland customers for the three and nine months ended September 30, 2015.March 31, 2016.
The costs related to default electricity supply are included in Purchased power and fuel. Operating revenues also include transmission enhancement credits that DPL receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.
Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Natural gas operating revenue includes sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated gas revenue includes the revenue DPL receives fromon-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other gas revenue consists ofoff-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.
Purchased power expense consists of the cost of electricity purchased by DPL to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased fuel expense consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased foroff-system sales.
The changes in DPL’s operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||||||
Increase (Decrease) | Increase (Decrease) | Increase (Decrease) | ||||||||||||||||||||||||||||||||||
Electric | Gas | Total | Electric | Gas | Total | Electric | Gas | Total | ||||||||||||||||||||||||||||
Weather | $ | 4 | $ | — | $ | 4 | $ | (4 | ) | $ | (5 | ) | $ | (9 | ) | $ | (2 | ) | $ | (6 | ) | $ | (8 | ) | ||||||||||||
Volume | 2 | — | 2 | 8 | 2 | 10 | (1 | ) | 6 | 5 | ||||||||||||||||||||||||||
Pricing — distribution revenues | 19 | 3 | 22 | |||||||||||||||||||||||||||||||||
Regulatory required programs | 6 | — | 6 | 7 | — | 7 | 1 | — | 1 | |||||||||||||||||||||||||||
Transmission revenue | 5 | — | 5 | 12 | — | 12 | ||||||||||||||||||||||||||||||
Transmission revenues | (2 | ) | — | (2 | ) | |||||||||||||||||||||||||||||||
Other | 1 | — | 1 | 2 | — | 2 | 1 | — | 1 | |||||||||||||||||||||||||||
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Total increase (decrease) | $ | 18 | $ | — | $ | 18 | $ | 25 | $ | (3 | ) | $ | 22 | |||||||||||||||||||||||
Total increase | $ | 16 | $ | 3 | $ | 19 | ||||||||||||||||||||||||||||||
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Revenue Decoupling. DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A modified fixed variable rate design, which would provide for a charge not tied to a customer’s volumetric consumption of electricity or natural gas, has been proposed for DPL electricity and natural gas customers in Delaware. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.
In accounting for the BSA in Maryland, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer.
Weather. The demand for electricity and natural gas in areas not subject to the BSA 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 months ended September 30, 2016March 31, 2017 compared to the same period in 2015, operating revenue net of purchased power and fuel expense was higher due to the impact of favorable summer weather conditions in DPL’s service territory. During the nine months ended September 30, 2016, compared to the same period in 2015, operating revenue net of purchased power and fuel expense was lower due to the impact of unfavorable winter weather conditions in DPL’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 a20-year period in DPL’s electric service territory and a30-year period in DPL’s natural gas service territory. The changes in heating and cooling degree days in DPL’s service territory for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 and normal weather consisted of the following:
% Change | ||||||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, | 2016 | 2015 | Normal | 2016 vs. 2015 | 2016 vs. Normal | |||||||||||||||||||||||||||||||||||
Electric Service Territory | % Change | |||||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, | 2017 | 2016 | Normal | 2017 vs. 2016 | 2017 vs. Normal | |||||||||||||||||||||||||||||||||||
Heating Degree-Days | 14 | 2 | 35 | 600.0 | % | (60.0 | )% | 2,002 | 2,247 | 2,417 | (10.9 | )% | (17.2 | )% | ||||||||||||||||||||||||||
Cooling Degree-Days | 1,103 | 897 | 836 | 23.0 | % | 31.9 | % | — | 3 | 2 | (100.0 | )% | (100.0 | )% | ||||||||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||
Heating Degree-Days | 2,812 | 3,275 | 2,974 | (14.1 | )% | (5.4 | )% | |||||||||||||||||||||||||||||||||
Cooling Degree-Days | 1,410 | 1,315 | 1,164 | 7.2 | % | 21.1 | % |
Three Months Ended March 31, Heating Degree-DaysNatural Gas Service Territory % Change 2017 2016 Normal 2017 vs. 2016 2017 vs. Normal 2,031 2,335 2,516 (13.0 )% (19.3 )%
Volume. The increase in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015,2016, primarily reflects the impact of moderate economiccustomer growth and increased natural gas average customer growth.usage.
Pricing — Distribution Revenues. The increase in electric operating revenues net of purchased power expense as a result of pricing for the three months ended March 31, 2017 compared to the same period in 2016 was primarily due to the impact of the new electric distribution and natural gas rates charged to Delaware customers that became effective in July and December 2016 and the impact of new electric distribution rates charged to Maryland customers that became effective in February 2017. See Note 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs. This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and income taxes. Refer to the operating and maintenance expense discussion below for additional information on included programs.
Transmission Revenue.Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered and other billing adjustments. The increasedecrease in revenue net of purchased power expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 is a result of higher rates effective June 1, 2015 related to increases in transmission plant investment and operating expenses and due to the establishment of a reserve recorded in September 2015 related to the FERC ROE challenges, partially offset by lower revenue related to the MAPP abandonment recovery period that ended in March 2016.2016, partially offset by higher rates effective June 1, 2016 related to increases in transmission plant investment and operating expenses.
Operating and Maintenance Expense
Three Months Ended September 30, | Increase (Decrease) | Nine Months Ended September 30, | Increase (Decrease) | Three Months Ended March 31, | Increase (Decrease) | |||||||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||||||||||||
Operating and maintenance expense — baseline | $ | 50 | $ | 74 | $ | (24 | ) | $ | 328 | $ | 222 | $ | 106 | $ | 72 | $ | 201 | $ | (129 | ) | ||||||||||||||||
Operating and maintenance expense — regulatory required programs(a) | 5 | 3 | 2 | 10 | 12 | (2 | ) | 1 | 3 | (2 | ) | |||||||||||||||||||||||||
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Total operating and maintenance expense | $ | 55 | $ | 77 | $ | (22 | ) | $ | 338 | $ | 234 | $ | 104 | $ | 73 | $ | 204 | $ | (131 | ) | ||||||||||||||||
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(a) | Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues. |
The changes in operating and maintenance expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015,2016, consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
Increase (Decrease) | Increase (Decrease) | Increase (Decrease) | ||||||||||
Baseline | ||||||||||||
Labor, other benefits, contracting and materials | $ | (3 | ) | $ | (4 | ) | $ | (4 | ) | |||
Storm-related costs | 1 | 4 | 7 | |||||||||
Uncollectible accounts expense | (2 | ) | (5 | ) | (5 | ) | ||||||
Remeasurement of AMI-related regulatory asset | 1 | 2 | ||||||||||
Deferral of merger-related costs to regulatory asset | — | (3 | ) | (9 | ) | |||||||
Write-off of construction work in progress | — | 4 | 3 | |||||||||
BSC and PHISCO allocations(a) | 5 | 24 | (16 | ) | ||||||||
Merger commitments(b) | (27 | ) | 77 | (103 | ) | |||||||
Other | 1 | 7 | (2 | ) | ||||||||
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(24 | ) | 106 | (129 | ) | ||||||||
Regulatory required programs | ||||||||||||
Purchased power administrative costs | 2 | (2 | ) | (2 | ) | |||||||
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Total (decrease) increase | $ | (22 | ) | $ | 104 | |||||||
Total decrease | $ | (131 | ) | |||||||||
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(a) | Primarily related to merger severance and compensation |
(b) | Primarily related to merger-related commitments for customer rate credits |
Depreciation Amortization and AccretionAmortization Expense
The changes in depreciation amortization and accretionamortization expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Depreciation expense(a) | $ | 2 | $ | 6 | ||||
Regulatory asset amortization(b) | 1 | 2 | ||||||
Delaware renewable energy portfolio standards deferral | 1 | (1 | ) | |||||
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Total increase | $ | 4 | $ | 7 | ||||
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Depreciation expense(a) Regulatory asset amortization(b) Total increase Increase (Decrease) $ 2 (2 ) $ —
(a) | Depreciation expense increased due to higher depreciation rates in Maryland effective February 2017 and due to ongoing capital expenditures. |
(b) | Regulatory asset amortization |
Taxes Other Than Income
Taxes other than income for the ninethree months ended September 30, 2016March 31, 2017 compared to the same period in 2015 increased primarily due to higher property taxes.2016 remained relatively constant.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 remained relatively constant.
Other, Net
Other, net for the three and nine months ended September 30, 2016 remained relatively levelMarch 31, 2017 compared to the same periodsperiod in 2015.2016 remained relatively constant.
Effective Income Tax Rate
DPL’s effective income tax rate was 30.2%16.2% and 37.5%11.1% for the three months ended September 30,March 31, 2017 and 2016, respectively. In the first quarter of 2017, DPL decreased its liability for unrecognized tax benefits by
$16 million resulting in a benefit to Income taxes and 2015, respectively. DPL’sa corresponding decrease in its effective income tax rate was 900.0% and 38.2% for the nine months ended September 30, 2016 and 2015, respectively.rate. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. As a result of the merger, DPL recorded an after-tax charge of $19 million during the nine months ended September 30, 2016 as a result of the assessment and remeasurement of certain federal and state uncertain tax positions.
DPL Electric Operating Statistics and Revenue Detail
Three Months Ended September 30, | % Change | Weather - Normal % Change | Nine Months Ended September 30, | % Change | Weather - Normal % Change | |||||||||||||||||||||||||||
Retail Deliveries to Customers (in GWhs) | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||||||||||||||
Retail Deliveries(a) | ||||||||||||||||||||||||||||||||
Residential | 1,601 | 1,425 | 12.4 | % | 9.9 | % | 4,066 | 4,297 | (5.4 | )% | 1.9 | % | ||||||||||||||||||||
Small commercial & industrial | 642 | 618 | 3.9 | % | 7.7 | % | 1,746 | 1,803 | (3.2 | )% | 2.6 | % | ||||||||||||||||||||
Large commercial & industrial | 1,250 | 1,283 | (2.6 | )% | 4.1 | % | 3,492 | 3,550 | (1.6 | )% | 1.2 | % | ||||||||||||||||||||
Public authorities & electric railroads | 9 | 11 | (18.2 | )% | 7.6 | % | 35 | 33 | 6.1 | % | (3.7 | )% | ||||||||||||||||||||
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Total retail deliveries | 3,502 | 3,337 | 4.9 | % | 7.3 | % | 9,339 | 9,683 | (3.6 | )% | 1.8 | % | ||||||||||||||||||||
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As of September 30, | ||||||||||||||||||||||||||||||||
Number of Electric Customers | 2016 | 2015 | ||||||||||||||||||||||||||||||
Residential | 455,640 | 453,114 | ||||||||||||||||||||||||||||||
Small commercial & industrial | 60,034 | 59,583 | ||||||||||||||||||||||||||||||
Large commercial & industrial | 1,414 | 1,412 | ||||||||||||||||||||||||||||||
Public authorities & electric railroads | 643 | 644 | ||||||||||||||||||||||||||||||
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Total | 517,731 | 514,753 | ||||||||||||||||||||||||||||||
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Three Months Ended March 31, | % Change | Weather - Normal % Change | ||||||||||||||||||||||||||||||||||||||||||||||
Retail Deliveries to Customers (in GWhs) | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||||||
Retail Deliveries(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Residential | 1,359 | 1,428 | (4.8 | )% | (0.3 | )% | ||||||||||||||||||||||||||||||||||||||||||
Small commercial & industrial | 531 | 572 | (7.2 | )% | (6.0 | )% | ||||||||||||||||||||||||||||||||||||||||||
Large commercial & industrial | 1,064 | 1,078 | (1.3 | )% | (0.6 | )% | ||||||||||||||||||||||||||||||||||||||||||
Public authorities & electric railroads | 13 | 14 | (7.1 | )% | (7.1 | )% | ||||||||||||||||||||||||||||||||||||||||||
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Total retail deliveries | 2,967 | 3,092 | (4.0 | )% | (1.5 | )% | ||||||||||||||||||||||||||||||||||||||||||
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As of March 31, | ||||||||||||||||||||||||||||||||||||||||||||||||
Number of Electric Customers | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||||||
Residential | 457,663 | 453,670 | ||||||||||||||||||||||||||||||||||||||||||||||
Small commercial & industrial | 60,289 | 59,860 | ||||||||||||||||||||||||||||||||||||||||||||||
Large commercial & industrial | 1,411 | 1,418 | ||||||||||||||||||||||||||||||||||||||||||||||
Public authorities & electric railroads | 642 | 643 | ||||||||||||||||||||||||||||||||||||||||||||||
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Total | 520,005 | 515,591 | ||||||||||||||||||||||||||||||||||||||||||||||
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Three Months Ended September 30, | % Change | Nine Months Ended September 30, | % Change | Three Months Ended March 31, | % Change | |||||||||||||||||||||||||||||||||||||||||||
Electric Revenue | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||
Retail Sales(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Residential | $ | 200 | $ | 181 | 10.5 | % | $ | 522 | $ | 533 | (2.1 | )% | $ | 181 | $ | 182 | (0.5 | )% | ||||||||||||||||||||||||||||||
Small commercial & industrial | 48 | 51 | (5.9 | )% | 143 | 145 | (1.4 | )% | 45 | 49 | (8.2 | )% | ||||||||||||||||||||||||||||||||||||
Large commercial & industrial | 24 | 26 | (7.7 | )% | 74 | 79 | (6.3 | )% | 25 | 25 | — | % | ||||||||||||||||||||||||||||||||||||
Public authorities & electric railroads | 2 | 3 | (33.3 | )% | 9 | 9 | — | % | 4 | 4 | — | % | ||||||||||||||||||||||||||||||||||||
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Total retail | 274 | 261 | 5.0 | % | 748 | 766 | (2.3 | )% | 255 | 260 | (1.9 | )% | ||||||||||||||||||||||||||||||||||||
Other revenue(b) | 40 | 34 | 17.6 | % | 124 | 109 | 13.8 | % | 41 | 43 | (4.7 | )% | ||||||||||||||||||||||||||||||||||||
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Total electric revenue(c) | $ | 314 | $ | 295 | 6.4 | % | $ | 872 | $ | 875 | (0.3 | )% | $ | 296 | $ | 303 | (2.3 | )% | ||||||||||||||||||||||||||||||
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(a) | Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from DPL, revenue also reflects the cost of energy and transmission. |
(b) | Other revenue includes transmission revenue from PJM and wholesale electric revenues. |
(c) | Includes operating revenues from affiliates totaling $2 million and |
DPL Natural Gas Operating Statistics and Revenue Detail
Retail Deliveries to Customers (in | Three Months Ended September 30, | % Change | Weather - Normal % Change | Nine Months Ended September 30, | % Change | Weather - Normal % Change | ||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||||||||||||||||||
Retail Deliveries | ||||||||||||||||||||||||||||||||
Residential | 1,121 | 1,111 | 0.9 | % | (5.1 | )% | 9,253 | 10,720 | (13.7 | )% | (4.1 | )% | ||||||||||||||||||||
Transportation & other | 1,166 | 1,144 | 1.9 | % | (0.6 | )% | 4,455 | 4,716 | (5.5 | )% | (0.9 | )% | ||||||||||||||||||||
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Total natural gas deliveries | 2,287 | 2,255 | 1.4 | % | (2.8 | )% | 13,708 | 15,436 | (11.2 | )% | (3.1 | )% | ||||||||||||||||||||
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As of September 30, | ||||||||||||||||||||||||||||||||
Number of Gas Customers | 2016 | 2015 | ||||||||||||||||||||||||||||||
Residential | 120,075 | 119,006 | ||||||||||||||||||||||||||||||
Commercial & industrial | 9,656 | 9,527 | ||||||||||||||||||||||||||||||
Transportation & other | 157 | 159 | ||||||||||||||||||||||||||||||
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Total | 129,888 | 128,692 | ||||||||||||||||||||||||||||||
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Three Months Ended September 30, | % Change | Nine Months Ended September 30, | % Change | |||||||||||||||||||||||||||||
Natural Gas Revenue | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||||||||||||||
Retail Sales(a) | ||||||||||||||||||||||||||||||||
Retail sales | $ | 13 | $ | 13 | — | % | $ | 87 | $ | 111 | (21.6 | )% | ||||||||||||||||||||
Transportation & other(b) | 4 | 6 | (33.3 | )% | 15 | 18 | (16.7 | )% | ||||||||||||||||||||||||
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Total natural gas revenues | $ | 17 | $ | 19 | (10.5 | )% | $ | 102 | $ | 129 | (20.9 | )% | ||||||||||||||||||||
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Three Months Ended March 31, | % Change | Weather - Normal % Change | ||||||||||||||
Retail Deliveries to Customers (in mmcf) | 2017 | 2016 | ||||||||||||||
Retail Deliveries | ||||||||||||||||
Residential | 5,932 | 6,060 | (2.1 | )% | 9.5 | % | ||||||||||
Transportation & other | 2,168 | 1,968 | 10.2 | % | 13.7 | % | ||||||||||
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Total natural gas deliveries | 8,100 | 8,028 | 0.9 | % | 10.5 | % | ||||||||||
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Number of Gas Customers Residential Commercial & industrial Transportation & other Total Natural Gas Revenue Retail Sales(a) Retail sales Transportation & other(b) Total natural gas revenues As of March 31, 2017 2016 121,362 120,046 9,855 9,772 156 158 131,373 129,976 Three Months Ended
March 31, % Change 2017 2016 $ 59 $ 53 11.3 % 7 6 16.7 % $ 66 $ 59 11.9 %
(a) | Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas. |
(b) | Transportation and other revenue includesoff-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. |
Three Months Ended September 30, | Favorable (Unfavorable) Variance | Nine Months Ended September 30, | Favorable (Unfavorable) Variance | Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 �� | 2016 | |||||||||||||||||||||||||||||||
Operating revenues | $ | 421 | $ | 386 | $ | 35 | $ | 982 | $ | 1,003 | $ | (21 | ) | $ | 275 | $ | 291 | $ | (16 | ) | ||||||||||||||||
Purchased power expense | 221 | 214 | (7 | ) | 520 | 552 | 32 | 137 | 158 | 21 | ||||||||||||||||||||||||||
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Revenue net of purchased power expense(a) | 200 | 172 | 28 | 462 | 451 | 11 | ||||||||||||||||||||||||||||||
Revenues net of purchased power expense(a) | 138 | 133 | 5 | |||||||||||||||||||||||||||||||||
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Other operating expenses | ||||||||||||||||||||||||||||||||||||
Operating and maintenance | 67 | 70 | 3 | 346 | 207 | (139 | ) | 76 | 212 | 136 | ||||||||||||||||||||||||||
Depreciation, amortization and accretion | 49 | 49 | — | 130 | 135 | 5 | ||||||||||||||||||||||||||||||
Depreciation and amortization | 35 | 40 | 5 | |||||||||||||||||||||||||||||||||
Taxes other than income | 1 | 2 | 1 | 6 | 5 | (1 | ) | 2 | 2 | — | ||||||||||||||||||||||||||
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Total other operating expenses | 117 | 121 | 4 | 482 | 347 | (135 | ) | 113 | 254 | 141 | ||||||||||||||||||||||||||
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Gain on sale of assets | — | — | — | 1 | — | 1 | ||||||||||||||||||||||||||||||
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Operating income (loss) | 83 | 51 | 32 | (19 | ) | 104 | (123 | ) | 25 | (121 | ) | 146 | ||||||||||||||||||||||||
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Other income and (deductions) | ||||||||||||||||||||||||||||||||||||
Interest expense, net | (15 | ) | (16 | ) | 1 | (47 | ) | (48 | ) | 1 | (15 | ) | (16 | ) | 1 | |||||||||||||||||||||
Other, net | 2 | 1 | 1 | 8 | 4 | 4 | 2 | 4 | (2 | ) | ||||||||||||||||||||||||||
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Total other income and (deductions) | (13 | ) | (15 | ) | 2 | (39 | ) | (44 | ) | 5 | (13 | ) | (12 | ) | (1 | ) | ||||||||||||||||||||
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Income (loss) before income taxes | 70 | 36 | 34 | (58 | ) | 60 | (118 | ) | 12 | (133 | ) | 145 | ||||||||||||||||||||||||
Income taxes | 23 | 14 | (9 | ) | (8 | ) | 23 | 31 | (16 | ) | (33 | ) | (17 | ) | ||||||||||||||||||||||
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Net income (loss) attributable to common shareholder | $ | 47 | $ | 22 | $ | 25 | $ | (50 | ) | $ | 37 | $ | (87 | ) | ||||||||||||||||||||||
Net income (loss) | $ | 28 | $ | (100 | ) | $ | 128 | |||||||||||||||||||||||||||||
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(a) | ACE evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. ACE believes Revenue net of purchased power expense is a useful measurement of its performance because it provides information that can be used to evaluate its operational performance. ACE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense 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. |
Net Income (Loss) Attributable to Common Shareholder
Three Months Ended September 30, 2016March 31, 2017 Compared to Three Months Ended September 30, 2015.March 31, 2016. ACE’s net income attributable to common shareholder for the three months ended September 30, 2016,March 31, 2017, was higher than the same period in 2015,2016, primarily due to an increase in operating revenue net of purchased power expense resulting from higher average customer usageelectric distribution revenues as a result of the distribution rate order issued by the NJBPU in August 2016, lower Operating and higher transmission revenue andmaintenance expense mostly due to merger-related costs recognized in March 2016 and a decrease in operating and maintenance expense reflecting a revision inincome tax reserves for uncertain tax positions related to the estimatedeductibility of ACE’scertain merger commitment costs associated with the most favored nation provision of the merger orders. The revision in estimate included a reduction in ACE’s merger commitment costs of $10 million, reflecting a reallocation of the most favored nation commitments among Exelon and ACE, such that more commitments are expected to be obligations of Exelon for energy efficiency and other programs as opposed to obligations of ACE for additional customer rate credits.commitments.
Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. ACE’s net loss attributable to common shareholder for the nine months ended September 30, 2016, compared unfavorably to ACE’s net income for the same period in 2015, primarily due to an increase in operating and maintenance expense due to merger-related costs.
Operating RevenueRevenues Net of Purchased Power Expense
Operating revenues include revenue from the distribution and supply of electricity to ACE’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that ACE receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All ACE customers have the choice to purchase electricity from competitive electric generation suppliers. The customer’s choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and nine months ended September 30, 2016,March 31, 2017, compared to the same periodsperiod in 2015,2016, consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Electric | 44 | % | 40 | % | 46 | % | 44 | % |
Three Months Ended March 31, | ||||||||
2017 | 2016 | |||||||
Electric | 49 | % | 47 | % |
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30,March 31, 2017 and 2016 and 2015 consisted of the following:
September 30, 2016 | September 30, 2015 | |||||||||||||||
Number of customers | % of total retail customers | Number of customers | % of total retail customers | |||||||||||||
Electric | 96,837 | 18 | % | 78,758 | 14 | % |
March 31, 2017 | March 31, 2016 | |||||||||||||||
Number of customers | % of total retail customers | Number of customers | % of total retail customers | |||||||||||||
Electric | 93,896 | 17 | % | 76,522 | 14 | % |
The costs related to default electricity supply are included in Purchased power expense. Operating revenues also include revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, revenue from the resale in the PJM RTO market ofwholesale markets for energy and capacity purchased under contacts with unaffiliated NUGs, and revenue from transmission enhancement credits.
Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Purchased power expense consists of the cost of electricity purchased by ACE to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders.
The changes in ACE’s operating revenue net of purchased power expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||
Increase (Decrease) | Increase (Decrease) | |||||||
Weather | $ | 2 | $ | (7 | ) | |||
Volume | 12 | 4 | ||||||
Distribution rate increase | 4 | 4 | ||||||
Regulatory required programs | (1 | ) | (10 | ) | ||||
Transmission revenues | 11 | 19 | ||||||
Other | — | 1 | ||||||
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Total increase | $ | 28 | $ | 11 | ||||
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Increase (Decrease) | ||||
Weather | (1 | ) | ||
Volume | (5 | ) | ||
Pricing — distribution revenues | 10 | |||
Regulatory required programs | (5 | ) | ||
Transmission revenues | 7 | |||
Other | (1 | ) | ||
Total increase | 5 | |||
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. During the three months ended September 30, 2016March 31, 2017 compared to the same period in 2015, operating revenue net of purchased power and fuel expense was higher due to the impact of favorable summer weather conditions in ACE’s service territory. During the nine months ended September 30, 2016, compared to the same period in 2015, operating revenue net of purchased power and fuel expense was lower due to the impact of slightly unfavorable winter weather conditions in ACE’s service territory.
For retail customers of ACE, distribution revenues are not decoupled forfrom the distribution of electricity by ACE, and thus are subject to variability due to changes in customer consumption. Therefore, changes in customer usage (due to weather conditions, energy prices, energy savings programs or other reasons) from period to period have a direct impact on reported distribution revenue for customers 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 a20-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, 2016March 31, 2017 compared to the same periodsperiod in 20152016 consisted of the following:
% Change | Normal | % Change | ||||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, | 2016 | 2015 | Normal | 2016 vs. 2015 | 2016 vs. Normal | |||||||||||||||||||||||||||||||||||
Three Months Ended March 31, | 2017 | 2016 | 2017 vs. 2016 | 2017 vs. Normal | ||||||||||||||||||||||||||||||||||||
Normal | ||||||||||||||||||||||||||||||||||||||||
Heating Degree-Days | 17 | — | 44 | — | % | (61.4 | )% | 2,150 | 2,270 | 2,488 | (5.3 | )% | (13.6 | )% | ||||||||||||||||||||||||||
Cooling Degree-Days | 1,006 | 883 | 786 | 13.9 | % | 28.0 | % | — | 4 | 1 | (100.0 | )% | (100.0 | )% | ||||||||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||
Heating Degree-Days | 2,938 | 3,524 | 3,143 | (16.6 | )% | (6.5 | )% | |||||||||||||||||||||||||||||||||
Cooling Degree-Days | 1,267 | 1,249 | 1,072 | 1.4 | % | 18.2 | % |
Volume. The increasedecrease in operating revenue net of purchased power expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015,2016, primarily reflects lower average customer usage, partially offset by the impact of higher average customer usage.growth.
Pricing — Distribution Rate Increase.Revenues. The increase in operating revenue net of purchased power expense for the three and nine months ended September 30, 2016,March 31, 2017, compared to the same periodsperiod in 2015,2016, was primarily due to the impact of the new electric distribution base rate charged to customers that became effective in August 2016 in accordance with the NJBPU approved electric rate case order.2016. See Note 5 — 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs. This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and income taxes. Refer to the depreciation and amortization expense discussion below for additional information on included programs.
Transmission Revenue.Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered and other billing adjustments. The increase in revenue net of purchased power expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 is a result of higher rates effective June 1, 20152016 related to increases in transmission plant investment and operating expenses, and due to the establishment of a reserve recorded in September 2015 related to the FERC ROE challenges.
Operating and Maintenance Expense
Three Months Ended September 30, | Increase (Decrease) | Nine Months Ended September 30, | Increase (Decrease) | Three Months Ended March 31, | Increase (Decrease) | |||||||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||||||||||||
Operating and maintenance expense — baseline | $ | 66 | $ | 69 | $ | (3 | ) | $ | 343 | $ | 204 | $ | 139 | $ | 75 | $ | 211 | $ | (136 | ) | ||||||||||||||||
Operating and maintenance expense — regulatory required programs(a) | 1 | 1 | — | 3 | 3 | — | 1 | 1 | — | |||||||||||||||||||||||||||
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Total operating and maintenance expense | $ | 67 | $ | 70 | $ | (3 | ) | $ | 346 | $ | 207 | $ | 139 | $ | 76 | $ | 212 | $ | (136 | ) | ||||||||||||||||
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(a) | Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues. |
The changes in operating and maintenance expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
Increase (Decrease) | Increase (Decrease) | Increase (Decrease) | ||||||||||
Baseline | ||||||||||||
Labor, other benefits, contracting and materials | $ | 3 | $ | 7 | $ | (2 | ) | |||||
Storm-related costs | — | 1 | 1 | |||||||||
BSC and PHISCO allocations(a) | 2 | 18 | (13 | ) | ||||||||
Uncollectible accounts expense | 1 | 2 | (1 | ) | ||||||||
Merger commitments(b) | (10 | ) | 111 | (120 | ) | |||||||
Other | 1 | — | (1 | ) | ||||||||
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Total (decrease) increase | $ | (3 | ) | $ | 139 | |||||||
Total decrease | $ | (136 | ) | |||||||||
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(a) | Primarily related to merger severance and compensation |
(b) | Primarily related to merger-related commitments for customer rate credits |
Depreciation Amortization and AccretionAmortization Expense
The changes in depreciation amortization and accretionamortization expense for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
Increase (Decrease) | Increase (Decrease) | Increase (Decrease) | ||||||||||
Depreciation expense(a) | $ | 1 | $ | 4 | $ | 1 | ||||||
Regulatory asset amortization(b) | (1 | ) | (9 | ) | (6 | ) | ||||||
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Total decrease | $ | — | $ | (5 | ) | $ | (5 | ) | ||||
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(a) | Depreciation expense increased due to ongoing capital expenditures. |
(b) | Regulatory asset amortization decreased for the three |
Taxes Other Than Income
Taxes other than income for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015,2016, remained relatively constant.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 20152016 remained relatively constant.
Other, Net
Other, net for the three and nine months ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015 increased2016 decreased primarily due to higherlower interest income from AFUDC equity.on uncertain tax positions.
Effective Income Tax Rate
ACE’s effective income tax rate was 32.9%(133.3)% and 38.9%24.8% for the three months ended September 30,March 31, 2017 and 2016, respectively. In the first quarter of 2017, ACE decreased its liability for unrecognized tax benefits by $22 million resulting in a benefit to Income taxes and 2015 respectively. ACE’sa corresponding decrease in its effective income tax rate was 13.8% and 38.3% for the nine months ended September 30, 2016 and 2015, respectively.rate. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. As a result of the merger, ACE recorded an after-tax charge of $21 million during the nine months ended September 30, 2016 as a result of the assessment and remeasurement of certain federal and state uncertain tax positions.
ACE Electric Operating Statistics and Revenue Detail
Three Months Ended September 30, | % Change | Weather - Normal % Change | Nine Months Ended September 30, | % Change | Weather - Normal % Change | Three Months Ended March 31, | % Change | Weather - Normal % Change | ||||||||||||||||||||||||||||||||||||||||
Retail Deliveries to Customers (in GWhs) | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||
Retail Deliveries(a) | ||||||||||||||||||||||||||||||||||||||||||||||||
Residential | 1,575 | 1,420 | 10.9 | % | 5.6 | % | 3,327 | 3,452 | (3.6 | )% | 1.6 | % | 879 | 938 | (6.3 | )% | (4.4 | )% | ||||||||||||||||||||||||||||||
Small commercial & industrial | 426 | 385 | 10.6 | % | 3.1 | % | 998 | 996 | 0.2 | % | 0.9 | % | 283 | 289 | (2.1 | )% | (1.4 | )% | ||||||||||||||||||||||||||||||
Large commercial & industrial | 1,032 | 933 | 10.6 | % | 4.0 | % | 2,705 | 2,669 | 1.3 | % | 1.2 | % | 765 | 820 | (6.7 | )% | (6.9 | )% | ||||||||||||||||||||||||||||||
Public authorities & electric railroads | 11 | 9 | 22.2 | % | — | % | 35 | 32 | 9.4 | % | — | % | 13 | 15 | (13.3 | )% | (13.3 | )% | ||||||||||||||||||||||||||||||
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Total retail deliveries | 3,044 | 2,747 | 10.8 | % | 4.7 | % | 7,065 | 7,149 | (1.2 | )% | 1.3 | % | 1,940 | 2,062 | (5.9 | )% | (5.0 | )% | ||||||||||||||||||||||||||||||
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As of September 30, | As of March 31, | |||||||||||||||||||||||||||||||||||||||||||||||
Number of Electric Customers | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||||
Residential | 483,542 | 482,348 | 485,691 | 482,718 | ||||||||||||||||||||||||||||||||||||||||||||
Small commercial & industrial | 63,826 | 63,671 | 60,999 | 60,858 | ||||||||||||||||||||||||||||||||||||||||||||
Large commercial & industrial | 845 | 893 | 3,761 | 3,828 | ||||||||||||||||||||||||||||||||||||||||||||
Public authorities & electric railroads | 593 | 564 | 612 | 583 | ||||||||||||||||||||||||||||||||||||||||||||
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Total | 548,806 | 547,476 | 551,063 | 547,987 | ||||||||||||||||||||||||||||||||||||||||||||
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Three Months Ended September 30, | % Change | Nine Months Ended September 30, | % Change | Three Months Ended March 31, | % Change | |||||||||||||||||||||||||||||||
Electric Revenue | 2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||||||||
Retail Sales(a) | ||||||||||||||||||||||||||||||||||||
Residential | $ | 249 | $ | 227 | 9.7 | % | $ | 530 | $ | 549 | (3.5 | )% | $ | 142 | $ | 150 | (5.3 | )% | ||||||||||||||||||
Small commercial & industrial | 55 | 53 | 3.8 | % | 133 | 135 | (1.5 | )% | 36 | 39 | (7.7 | )% | ||||||||||||||||||||||||
Large commercial & industrial | 57 | 56 | 1.8 | % | 158 | 155 | 1.9 | % | 45 | 51 | (11.8 | )% | ||||||||||||||||||||||||
Public authorities & electric railroads | 4 | 3 | 33.3 | % | 10 | 9 | 11.1 | % | 3 | 3 | — | % | ||||||||||||||||||||||||
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Total retail | 365 | 339 | 7.7 | % | 831 | 848 | (2.0 | )% | 226 | 243 | (7.0 | )% | ||||||||||||||||||||||||
Other revenue(b) | 56 | 47 | 19.1 | % | 151 | 155 | (2.6 | )% | 49 | 48 | 2.1 | % | ||||||||||||||||||||||||
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Total electric revenue(c) | $ | 421 | $ | 386 | 9.1 | % | $ | 982 | $ | 1,003 | (2.1 | )% | $ | 275 | $ | 291 | (5.5 | )% | ||||||||||||||||||
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(a) | Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from ACE, revenue also reflects the cost of energy and transmission. |
(b) | Other revenue includes transmission revenue from PJM and wholesale electric revenues. |
(c) | Includes operating revenues from affiliates totaling $1 million and $1 million for the three months ended |
Liquidity and Capital Resources
Exelon activity presented below includes the activity of PHI, Pepco, DPL and ACE, from the PHI Merger effective date of March 24, 2016 through September 30, 2016.March 31, 2017. Exelon prior year activity is unadjusted for the effects of the PHI Merger. Due to the application of push-down accounting to the PHI entity, PHI’s activity is presented in two separate reporting periods, the legacy PHI activity through March 23, 2016 (Predecessor), and PHI activity for the remainder of the period after the PHI merger date (Successor). For each of Pepco, DPL and
ACE the activity presented below include its activity for the ninethree months ended September 30, 2016March 31, 2017 and 2015.2016. All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditureexpenditures requirements are provided by internally generated cash flows from operations 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 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 billion. In addition, Generation has $525 million in bilateral credit facilities with banks which have various expirations dates between December 2016October 2017 and May 2021.January 2019. The Registrants utilize their credit facilities to support their commercial paper programs, and provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for further discussion. 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, ComEd, PECO, BGE, Pepco, DPL and ACE 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 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further discussion of the Registrants’ debt and credit agreements.
NRC Minimum Funding Requirements
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 12 — Nuclear Decommissioning to the Combined Notes to Consolidated Financial Statements for additional information on the NRC minimum funding requirements.
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 investments could appreciate in value. A shortfall could require Exelon to post parental guarantees for Generation’s share of the obligations. However, the amount of any required guarantees will ultimately depend on the decommissioning approach adopted at each site, the associated level of costs, and the decommissioning trust fund investment performance going forward. Within two years after shutting down a plant, Generation must submit a post-shutdown decommissioning activities report (PSDAR) to the NRC that includes the planned option for decommissioning the site. As discussed in Note 12 — Nuclear Decommissioning, Generation filed its biennial decommissioning funding status report with the NRC on March 31, 2017 and
demonstrated adequate funding assurance for all nuclear units currently operating, as compared to previous estimates prior to the reversal of the early retirement decision for Clinton and Quad Cities. As of March 31, 2017, TMI passes the NRC minimum funding test based on its current license life. However, in the event of an early retirement of TMI, the most costly estimates could require parental guarantees of up to $35 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, the NRC must approve an additional exemption in order for the plant’s owner(s) to utilize the NDT fund to pay fornon-radiological decommissioning costs (i.e. spent fuel management and site restoration costs). If a unit does not receive this exemption, the costs would be borne by the owner(s). While the ultimate amounts may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the United States Department of Energy reimbursement agreements or future litigation, across the three alternative decommissioning approaches available, if an early retirement decision is made and TMI were to fail the exemption test, Generation could incur spent fuel management and site restoration costs over the next ten years of up to $145 million net of taxes.
Junior Subordinated Notes
In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes may use debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon will receive $1.15 billion upon settlement on June 1, 2017, of the forward equity purchase contract. Exelon currently expects the number of equity shares to be issued to range from 26 million to 33 million dependent on Exelon’s stock price at the time of settlement pursuant to the equity unit terms. Until settlement of the equity purchase contract, earnings per share dilution resulting from the equity units is being determined under the treasury stock method.
For the three months ended March 31, 2017 and 2016, contract payments of $11 million related to the Contract Payment Obligation were included within Retirements of long-term debt in Exelon’s Consolidated Statements of Cash Flows.
Cash Flows from Operating Activities
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.
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, natural gas distribution services. The Utility Registrants’ distribution services are provided to an established and diverse base of retail customers. The Utility Registrants’ future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, competitive suppliers, and their ability to achieve operating cost reductions.
See Notes 3 — Regulatory Matters and 2324 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 20152016 Form10-K for further discussion of regulatory and legal proceedings and proposed legislation. See Note 7 — Regulatory Matters and Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the PHI 2015 Form 10-K.
The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the ninethree months ended September 30, 2016March 31, 2017 and 2015:2016:
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||||||||||
2016(c) | 2015 | Variance | 2017 | 2016(c) | Variance | |||||||||||||||||||
Net income | $ | 956 | $ | 1,959 | $ | (1,003 | ) | $ | 981 | $ | 123 | $ | 858 | |||||||||||
Add (subtract): | ||||||||||||||||||||||||
Non-cash operating activities(a) | 5,946 | 3,900 | 2,046 | 1,233 | 1,942 | (709 | ) | |||||||||||||||||
Pension and non-pension postretirement benefit contributions | (283 | ) | (430 | ) | 147 | (307 | ) | (239 | ) | (68 | ) | |||||||||||||
Income taxes | 527 | 300 | 227 | 50 | 47 | 3 | ||||||||||||||||||
Changes in working capital and other noncurrent assets and liabilities(b) | (516 | ) | (197 | ) | (319 | ) | (640 | ) | (623 | ) | (17 | ) | ||||||||||||
Option premiums (paid) received, net | (24 | ) | 27 | (51 | ) | (6 | ) | 17 | (23 | ) | ||||||||||||||
Counterparty collateral received, net | 757 | 115 | 642 | |||||||||||||||||||||
Collateral (posted) received, net | (110 | ) | 206 | (316 | ) | |||||||||||||||||||
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Net cash flows provided by operations | $ | 7,363 | $ | 5,674 | $ | 1,689 | $ | 1,201 | $ | 1,473 | $ | (272 | ) | |||||||||||
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(a) | Represents, when applicable, depreciation, amortization and accretion, net fair value changes related to derivatives, deferred income taxes, provision for uncollectible accounts, pension and other postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense, impairment of long-lived assets, PHI merger commitment and severance charges, and othernon-cash charges. See Note |
(b) | Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt. |
(c) | Includes PHI Consolidated activity from March 24, 2016 to |
Pension and Other Postretirement Benefits
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions andat-risk status as defined by the Pension Protection Act of 2006, management of the pension obligation and regulatory implications. On July 6, 2012, President Obama signed into law the Moving Ahead for Progress in the Twenty-first Century Act, which contains a pension funding provision that results in lower pension contributions in the near term while increasing the premiums pension plans pay to the Pension Benefit Guaranty Corporation. On August 8, 2014, this funding relief was extended for five years. On November 2, 2015 the funding relief was extended for an additional three years and premiums pension plans pay to the Pension Benefit Guaranty Corporation were further increased.
OPEB funding generally follows accounting cost, subjectcost; however, Exelon’s management has historically considered several factors in determining the level of contributions to adjustment forits funded other considerations such aspostretirement benefit plans, including liabilities management, levels of benefit claims paid and regulatory implications.implications (amounts deemed prudent to meet regulator expectations and best assure continued recovery).
To the extent interest rates decline significantly or the pension plans do not earn the expected asset return rates, annual pension contribution requirements in future years could increase. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.
Tax Matters
The Registrants’ future cash flows from operating activities may be affected by the following tax matters:
In order to appeal the Tax Court’s like-kind exchange decision, Exelon is required to pay the tax, penalty and interest at the time Exelon files its appeal (expected earlyin the third quarter of 2017). While the final calculation of tax, penalties and interest has not yet been finalized by the IRS, Exelon estimates that a payment of approximately $1.4 billion related to the like-kind exchange will be due, including $300 million from ComEd, in the first quarter of 2017. While Exelon will receive a tax benefit of
that a payment of approximately |
Of the above amounts payable, Exelon deposited with the IRS approximately $1.25 billion in October of 2016. The remaining amount will be paid in earlythe third quarter of 2017 at the time Exelon files its appeal of the Tax Court decision. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings.
In April of 2016, Exelon received tax refunds of approximately $460 million related to IRS positions settled in prior tax years. Of this amount, approximately $195 million of the refund is attributable to Generation and the remaining $265 million is attributable to ComEd.
State and local governments continue to face increasing financial challenges, which may increase the risk of additional income tax levies, property taxes and other taxes or the imposition, extension or permanence of temporary tax levies.
Cash flows from operations for the ninethree months ended September 30,March 31, 2017 and 2016 and 2015 by Registrant were as follows:
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||
2016 | 2015 | 2017 | 2016 | |||||||||||||
Exelon | $ | 7,363 | $ | 5,674 | $ | 1,201 | $ | 1,473 | ||||||||
Generation | 3,723 | 3,206 | 740 | 782 | ||||||||||||
ComEd | 1,749 | 1,346 | 145 | 284 | ||||||||||||
PECO | 582 | 567 | 64 | 138 | ||||||||||||
BGE | 660 | 696 | 168 | 273 | ||||||||||||
Pepco | 504 | 213 | 29 | 258 | ||||||||||||
DPL | 267 | 188 | 122 | 147 | ||||||||||||
ACE | 315 | 178 | 58 | 246 |
Successor | Predecessor | |||||||||||||||
March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | Nine Months Ended September 30, 2015 | ||||||||||||||
PHI | $ | 546 | $ | 264 | $ | 601 |
Successor | Predecessor | |||||||||||||||
Three Months Ended March 31, 2017 | March 24, 2016 to March 31, 2016 | January 1, 2016 to March 23, 2016 | ||||||||||||||
PHI | $ | 194 | $ | (3 | ) | $ | 264 |
Changes in the Registrants’ cashRegistrants’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 ninethree months ended September 30,March 31, 2017 and 2016 and 2015 were as follows:
Generation
Depending upon whether Generation is in a netmark-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 thean exchange or in the OTC markets. During the ninethree months ended September 30,March 31, 2017 and 2016, and 2015, Generation had net (payments)/collections of counterparty cash collateral of $759$(102) million and $186$198 million, respectively, primarily due to market conditions that resulted in changes to Generation’s netmark-to-market position.
During the ninethree months ended September 30,March 31, 2017 and 2016, and 2015, Generation had net (payments)/collections of approximately $(24)$(6) million and $27$17 million, respectively, related to purchases and sales of options. The level of option activity in a given period may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.
ComEd
During ninethree months ended September 30,March 31, 2017 and 2016, and 2015, ComEd posted approximately $2$8 million and $41received a return of $7 million of cash collateral towith PJM, respectively. ComEd’s collateral posted with PJM has decreasedincreased year over year primarily due to lower PJM billings.a reduction in ComEd’s share of Exelon’s unsecured credit with PJM. As of September 30,March 31, 2017 and 2016, and 2015, ComEd had approximately $33$32 million and $41$24 million cash collateral posted with PJM, respectively.
PHI, Pepco, DPL and ACEFor further discussion regarding changes innon-cash
During the nine months ended September 30, 2016, Pepco, DPL and ACE received tax refund allocations from PHI in connection with the Global Tax Settlement of $147 million, $56 million and $167 million, respectively. See operating activities, please refer to Note 1118 — Income TaxesSupplemental Financial Information of the PHI 2015 Form 10-K for additional information.Combined Notes to the Financial Statements.
Cash Flows from Investing Activities
Cash flows used in investing activities for the ninethree months ended September 30,March 31, 2017 and 2016 and 2015 by Registrant were as follows:
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||
2016 | 2015 | 2017 | 2016 | |||||||||||||
Exelon | $ | (13,219 | ) | $ | (5,689 | ) | $ | (2,411 | ) | $ | (8,548 | ) | ||||
Generation | (3,278 | ) | (3,020 | ) | (1,212 | ) | (1,204 | ) | ||||||||
ComEd | (1,919 | ) | (1,646 | ) | (529 | ) | (626 | ) | ||||||||
PECO | (438 | ) | (425 | ) | (27 | ) | (351 | ) | ||||||||
BGE | (614 | ) | (491 | ) | (181 | ) | (191 | ) | ||||||||
Pepco | (435 | ) | (357 | ) | (144 | ) | (136 | ) | ||||||||
DPL | (254 | ) | (240 | ) | (80 | ) | (81 | ) | ||||||||
ACE | (227 | ) | (216 | ) | (85 | ) | (100 | ) |
Successor | Predecessor | |||||||||||||
March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | Nine Months Ended September 30, 2015 | ||||||||||||
PHI | $ | (631 | ) | $ | (343 | ) | $ | (835 | ) |
Successor | Predecessor | |||||||||||||||
Three Months Ended March 31, 2017 | March 24, 2016 to March 31, 2016 | January 1, 2016 to March 23, 2016 | ||||||||||||||
PHI | $ | (321 | ) | $ | (30 | ) | $ | (343 | ) |
Significant investing cash flow impacts for the Registrants for three months ended March 31, 2017 and 2016 were as follows:
Exelon
During the three months ended March 31, 2017, Exelon had expenditures of $23 million and $182 million relating to the acquisitions of ConEdison Solutions and the FitzPatrick facility, respectively. During the three months ended March 31, 2016, Exelon had expenditures of $6.6 billion relating to the acquisition of PHI.
During the three months ended March 31, 2016, Exelon had proceeds of $360 million as a result of early termination of direct financing leases.
Generation
During the three months ended March 31, 2017, Exelon had expenditures of $23 million and $182 million relating to the acquisitions of ConEdison Solutions and the FitzPatrick facility, respectively.
Capital Expenditure Spending
Generation
Generation has entered into several agreements to acquire equity interests in privately held and development stage entities which develop energy-related technologies. The agreements contain a series of scheduled investment commitments, includingin-kind service contributions. There are approximately $108$19 million of anticipated expenditures remaining through 20182019 to fund anticipated planned capital and operating needs of the associated companies. See Note 2324 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 20152016 Form10-K for further details of Generation’s equity interests.
Capital expenditures by Registrant for the ninethree months ended September 30,March 31, 2017 and 2016 and 2015 and projected amounts for the full year 20162017 are as follows:
Projected Full Year 2016(a) | Nine Months Ended September 30, | Projected Full Year 2017(a) | Three Months Ended March 31, | |||||||||||||||||||||
2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||
Exelon | $ | 8,821 | $ | 6,368 | $ | 5,443 | $ | 8,225 | $ | 2,114 | $ | 2,202 | ||||||||||||
Generation | 3,375 | 2,651 | 2,774 | 2,625 | 923 | 1,125 | ||||||||||||||||||
ComEd(b) | 2,625 | 1,950 | 1,670 | 2,200 | 535 | 639 | ||||||||||||||||||
PECO | 650 | 448 | 435 | 775 | 159 | 195 | ||||||||||||||||||
BGE | 850 | 611 | 506 | 925 | 166 | 176 | ||||||||||||||||||
Pepco | 500 | 392 | 374 | 600 | 139 | 109 | ||||||||||||||||||
DPL | 275 | 260 | 246 | 400 | 82 | 81 | ||||||||||||||||||
ACE | 275 | 227 | 212 | 325 | 88 | 101 | ||||||||||||||||||
Other(d) | 100 | 84 | 58 |
Projected Full Year 2016(a)(c) | Successor | Predecessor | ||||||||||||||||||
March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | Nine Months Ended September 30, 2015 | ||||||||||||||||||
PHI | $ | 1,050 | $ | 624 | $ | 273 | $ | 855 |
Projected Full Year 2017(a) | Successor | Predecessor | ||||||||||||||||||
Three Months Ended March 31, 2017 | March 24, 2016 to March 31, 2016 | January 1, 2016 to March 23, 2016 | ||||||||||||||||||
PHI(d) | $ | 1,400 | $ | 320 | $ | 29 | $ | 273 |
(a) | Total projected capital expenditures do not include adjustments fornon-cash activity. |
(b) | The |
(c) |
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(d) |
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Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Generation
Approximately 32%35% and 38%22% of the projected 20162017 capital expenditures at Generation are for the acquisition of nuclear fuel and growth (primarily new plant construction and distributed generation), respectively, with the remaining amounts reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that they will fund capital expenditures with internally generated funds and borrowings.
ComEd, PECO, BGE, Pepco, DPL and ACE
Approximately 88%, 97%, 100%, 100%, 100%89% of the projected 2017 capital expenditures at ComEd and 100% of the projected 2016of the projected 2017 capital expenditures at ComEd, PECO, BGE, Pepco, DPL, and ACE respectively, are for continuing projects to
maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as ComEd’s reliability related investments required under EIMA, and the Utility Registrants’ construction commitments under PJM’s RTEP. In addition to the capital expendituresexpenditure for continuing projects, ComEd’s total expenditures include smart grid/smart meter technology required under EIMA and for PECO, BGE, Pepco, DPL, and ACE, include capital expenditures related to their respective smart meter programs.EIMA.
The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance
expenditures to ensure their transmission lines meet NERC standards. In 2010, NERC provided guidance to transmission owners that recommended the Utility Registrants perform assessments of their transmission lines. ComEd, PECO and BGE submitted their finalbi-annual reports to NERC in January 2014. ComEd, PECO and BGE will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd’s, PECO’s and BGE’s forecasted 20162017 capital expenditures above reflect capital spending for remediation to be completed through 2017.2018. Pepco, DPL and ACE have substantially completed their assessments and thus do not expect significant capital expenditures related to this guidance in 2016.2017.
The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent, including ComEd’s capital expenditures associated with EIMA as further discussed in Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.
Cash Flows from Financing Activities
Cash flows provided by (used in) financing activities for the ninethree months ended September 30,March 31, 2017 and 2016 and 2015 by Registrant were as follows:
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||
2016 | 2015 | 2017 | 2016 | |||||||||||||
Exelon | $ | 1,251 | $ | 5,402 | $ | 1,184 | $ | 1,533 | ||||||||
Generation | (501 | ) | (421 | ) | 582 | 368 | ||||||||||
ComEd | 147 | 285 | 359 | 296 | ||||||||||||
PECO | 77 | (140 | ) | (72 | ) | (69 | ) | |||||||||
BGE | 286 | (242 | ) | 1 | (86 | ) | ||||||||||
Pepco | 28 | 148 | 114 | (103 | ) | |||||||||||
DPL | (14 | ) | 53 | (44 | ) | (68 | ) | |||||||||
ACE | 74 | 40 | (20 | ) | (27 | ) |
Successor | Predecessor | |||||||||||||||
March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | Nine Months Ended September 30, 2015 | ||||||||||||||
PHI | $ | 65 | $ | 372 | $ | 491 |
Successor | Predecessor | |||||||||||||||
Three Months Ended March 31, 2017 | March 24, 2016 to March 31, 2016 | January 1, 2016 to March 23, 2016 | ||||||||||||||
PHI | $ | 66 | $ | (135 | ) | $ | 372 |
Debt
See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further details of the Registrants’ debt issuances.
Dividends
Cash dividend payments and distributions during the ninethree months ended September 30,March 31, 2017 and 2016 and 2015 by Registrant were as follows:
Nine Months Ended September 30, | Three Months Ended March 31, | |||||||||||||||
2016 | 2015 | 2017 | 2016 | |||||||||||||
Exelon | $ | 873 | $ | 819 | $ | 303 | $ | 287 | ||||||||
Generation | 167 | 2,368 | 164 | 55 | ||||||||||||
ComEd | 275 | 226 | 105 | 91 | ||||||||||||
PECO | 208 | 209 | 72 | 69 | ||||||||||||
BGE(a) | 142 | 126 | 49 | 48 | ||||||||||||
Pepco | 92 | 91 | 30 | 39 | ||||||||||||
DPL | 39 | 80 | 30 | 38 | ||||||||||||
ACE | 24 | 12 | 10 | 11 |
PHI PHI Successor Predecessor March 24, 2016 to
September 30, 2016 January 1, 2016 to
March 23, 2016 Nine Months Ended
September 30, 2015 $ 174 $ — $ 206 Successor Predecessor Three Months Ended
March 31, 2017 March 24, 2016 to
March 31, 2016 January 1, 2016 to
March 23, 2016 $ 69 $ 108 $ —
(a) | Includes dividends paid on BGE’s preference stock. |
Quarterly dividends declared by the Exelon Board of Directors during the ninethree months ended September 30, 2016March 31, 2017 and for the thirdsecond quarter of 20162017 were as follows:
Period | Declaration Date | Shareholder of Record Date | Dividend Payable Date | Cash per Share(a) | ||||||||||||
First Quarter 2016 | January 26, 2016 | February 12, 2016 | March 10, 2016 | $ | 0.310 | |||||||||||
Second Quarter 2016 | April 26, 2016 | May 13, 2016 | June 10, 2016 | $ | 0.318 | |||||||||||
Third Quarter 2016 | July 26, 2016 | August 15, 2016 | September 9, 2016 | $ | 0.318 | |||||||||||
Fourth Quarter 2016 | October 25, 2016 | November 15, 2016 | December 9, 2016 | $ | 0.318 |
Period | Declaration Date | Shareholder of Record Date | Dividend Payable Date | Cash per Share(a) | ||||||
First Quarter 2017 | January 31, 2017 | February 15, 2017 | March 10, 2017 | $ | 0.3275 | |||||
Second Quarter 2017 | April 25, 2017 | May 15, 2017 | June 9, 2017 | $ | 0.3275 |
(a) | Exelon’s Board of Directors approved a revised dividend policy. The approved policy will raise the dividend 2.5% each year for the next three years, beginning with the June 2016 dividend and subject to Board approval. |
Short-Term Borrowings
Short-term borrowings incurred (repaid) during the ninethree months ended September 30,March 31, 2017 and 2016 and 2015 by Registrant were as follows:
Nine months ended September 30, | Three Months Ended March 31, | |||||||||||||||
2016 | 2015 | 2017 | 2016 | |||||||||||||
Exelon | $ | (1,014 | ) | $ | 230 | $ | 781 | $ | 1,770 | |||||||
Generation | 43 | — | 18 | 1,500 | ||||||||||||
ComEd | (284 | ) | 300 | 365 | 349 | |||||||||||
BGE | (210 | ) | (70 | ) | 50 | (60 | ) | |||||||||
Pepco | (64 | ) | (56 | ) | 144 | (64 | ) | |||||||||
DPL | (88 | ) | (40 | ) | — | (30 | ) | |||||||||
ACE | (5 | ) | 98 | — | (5 | ) |
Successor | Predecessor | |||||||||||||||
March 24, 2016 to September 30, 2016 | January 1, 2016 to March 23, 2016 | Nine Months Ended September 30, 2015 | ||||||||||||||
PHI | $ | (820 | ) | $ | 379 | $ | 399 |
Successor | Predecessor | |||||||||||
Three Months Ended March 31, 2017 | March 24, 2016 to March 31, 2016 | January 1, 2016 to March 23, 2016 | ||||||||||
PHI | $ | (355 | ) | $ | (20 | ) | $ | 379 |
Contributions from Parent/Member
Contributions received from Parent/Member for the ninethree months ended September 30,March 31, 2017 and 2016 and 2015 by Registrant were as follows:
Nine months ended September 30, | ||||||||
2016 | 2015 | |||||||
Generation | $ | 142 | $ | 55 | ||||
ComEd | 188 | (a) | 75 | (a) | ||||
PECO | 18 | 16 | ||||||
BGE | 28 | (a) | 6 | |||||
Pepco | 187 | (b) | 112 | (b) | ||||
DPL | 113 | (b) | 75 | (b) | ||||
ACE | 139 | (b) | — |
Three Months Ended March 31, | ||||||||
2017 | 2016 | |||||||
Generation | $ | — | $ | 44 | ||||
ComEd(a)(b) | 100 | 39 | ||||||
BGE(b) | — | 21 |
|
Successor | Predecessor | |||||||||||||||
Three Months Ended March 31, 2017 | March 24, 2016 to March 31, 2016 | January 1, 2016 to March 23, 2016 | ||||||||||||||
PHI(b) | $ | 500 | $ | — | $ | — |
(a) |
|
(b) | Contribution paid by |
Pursuant to the orders approving the merger, Exelon made equity contributions of $73 million, $46 million and $49 million to Pepco, DPL and ACE, respectively, in the second quarter of 2016 to fund the after-tax amount of the customer bill credit and the customer base rate credit.
Redemptions of Preference Stock
On July 3, 2016, BGE redeemed all 400,000 shares of its outstanding 7.125% Cumulative Preference Stock, 1993 Series and all 600,000 shares of its outstanding 6.99% Cumulative Preference Stock, 1995 Series for $100 million, plus accrued and unpaid dividends. On September 18, 2016, BGE redeemed all remaining 500,000 shares of its outstanding 6.97% Cumulative Preference Stock, 1993 Series and all 400,000 shares of its outstanding 6.70% Cumulative Preference Stock, 1995 Series for $90 million, plus accrued and unpaid dividends. See Note 17 — Earnings Per Share and Equity of the Combined Notes to Consolidated Financial Statements for further details.
Other
For the ninethree months ended September 30, 2016,March 31, 2017, other financing activities primarily consist of debt issuance costs. See Note 10 — Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for further details of the Registrants’ debt issuances.
Credit Matters
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 $9.5 billion in aggregate total commitments of which $7.9$8.0 billion was available as of September 30, 2016,March 31, 2017, 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 during the thirdfirst quarter of 20162017 to fund their short-term liquidity needs, when necessary. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See PART I. ITEM 1A. RISK FACTORS of the Exelon 20152016 Form10-K for further 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, 2016,March 31, 2017, it would have been required to provide incremental collateral of $1.9$1.8 billion to meet collateral obligations for derivatives,non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within its current available credit facility capacities of $4.2$4.3 billion.
The following table presents the incremental collateral that each utility registrant would have been required to provide in the event each utility registrantUtility Registrant lost its investment grade credit rating at September 30, 2016March 31, 2017 and available credit facility capacity prior to any incremental collateral at September 30, 2016:March 31, 2017:
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 | $ | 17 | $ | — | $ | 998 | $ | 11 | $ | — | $ | 998 | ||||||||||||
PECO | 3 | 25 | 598 | 2 | 27 | 598 | ||||||||||||||||||
BGE | 2 | 29 | 600 | 11 | 47 | 598 | ||||||||||||||||||
Pepco | — | — | 300 | 6 | — | 300 | ||||||||||||||||||
DPL | 3 | 9 | 300 | 4 | 11 | 300 | ||||||||||||||||||
ACE | — | — | 299 | — | — | 300 |
(a) | Represents incremental collateral related to natural gas procurement contracts. |
Exelon Credit Facilities
Exelon, Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes. 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. PHI meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes. 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.
The following table reflects the Registrants’ commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at September 30, 2016:March 31, 2017:
Commercial Paper Programs
Commercial Paper Issuer | Maximum Program Size(a)(b) | Outstanding Commercial Paper at September 30, 2016 | Average Interest Rate on Commercial Paper Borrowings for the Nine Months Ended September 30, 2016 | Maximum Program Size(a)(b) | Outstanding Commercial Paper at March 31, 2017 | Average Interest Rate on Commercial Paper Borrowings for the Three Months Ended March 31, 2017 | ||||||||||||||||||
Exelon Corporate | $ | 600 | $ | — | 0.70 | % | $ | 600 | $ | 204 | 1.15 | % | ||||||||||||
Generation | 5,300 | — | 1.01 | % | 5,300 | 579 | 1.11 | % | ||||||||||||||||
ComEd | 1,000 | 10 | 0.77 | % | 1,000 | 365 | 1.07 | % | ||||||||||||||||
PECO | 600 | — | — | % | 600 | — | 1.12 | % | ||||||||||||||||
BGE | 600 | — | 0.77 | % | 600 | 95 | 1.01 | % | ||||||||||||||||
Pepco | 500 | — | 0.67 | % | 500 | 167 | 1.05 | % | ||||||||||||||||
DPL | 500 | 17 | 0.69 | % | 500 | — | — | % | ||||||||||||||||
ACE | 350 | — | 0.65 | % | 350 | — | — | % |
(a) | Excludes $525 million bilateral credit facilities that do not back Generation’s commercial paper program. |
(b) | Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $50 million, $34 million, $34 million, $5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities’ service territories. These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of |
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program.
While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant’s credit facility, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available
capacity under its credit facility. At September 30, 2016,March 31, 2017, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:
Credit Agreements
Borrower | Facility Type | Aggregate Bank Commitment(a)(b)(c) | Facility Draws | Outstanding Letters of Credit | Available Capacity at September 30, 2016 | Facility Type | Aggregate Bank Commitment(a)(b)(c) | Facility Draws | Outstanding Letters of Credit | Available Capacity at March 31, 2017 | ||||||||||||||||||||||||||||||||||
Actual | To Support Additional Commercial Paper(d) | Actual | To Support Additional Commercial Paper(d) | |||||||||||||||||||||||||||||||||||||||||
Exelon Corporate | Syndicated Revolver | $ | 600 | $ | — | $ | 29 | $ | 571 | $ | 571 | Syndicated Revolver | $ | 600 | $ | — | $ | 44 | $ | 556 | $ | 352 | ||||||||||||||||||||||
Generation(e) | Syndicated Revolver | 5,300 | — | 1,264 | 4,036 | 4,036 | Syndicated Revolver | 5,300 | — | 1,039 | 4,261 | 3,683 | ||||||||||||||||||||||||||||||||
Generation | Bilaterals | 525 | 40 | 319 | 166 | — | Bilaterals | 525 | 135 | 329 | 61 | — | ||||||||||||||||||||||||||||||||
ComEd | Syndicated Revolver | 1,000 | — | 2 | 998 | 988 | Syndicated Revolver | 1,000 | — | 2 | 998 | 633 | ||||||||||||||||||||||||||||||||
PECO | Syndicated Revolver | 600 | — | 2 | 598 | 598 | Syndicated Revolver | 600 | — | 2 | 598 | 598 | ||||||||||||||||||||||||||||||||
BGE | Syndicated Revolver | 600 | — | — | 600 | 600 | Syndicated Revolver | 600 | — | 3 | 598 | 503 | ||||||||||||||||||||||||||||||||
Pepco | Syndicated Revolver | 300 | — | — | 300 | 300 | Syndicated Revolver | 300 | — | — | 300 | 133 | ||||||||||||||||||||||||||||||||
DPL | Syndicated Revolver | 300 | — | — | 300 | 283 | Syndicated Revolver | 300 | — | — | 300 | 300 | ||||||||||||||||||||||||||||||||
ACE | Syndicated Revolver | 300 | — | 1 | 299 | 299 | Syndicated Revolver | 300 | — | — | 300 | 300 |
(a) | Excludes $129 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE. These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of |
(b) | Pepco, DPL and ACE’s revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility |
(c) | Excludes nonrecourse debt letters of credit, see Note 14 — Debt and Credit Agreements in the Exelon |
(d) | Excludes $525 million bilateral credit facilities that do not back Generation’s commercial paper program. |
(e) | Excludes ExGen Texas Power Financing’s $4 million of borrowed debt on its revolving credit facility. |
As of September 30, 2016,March 31, 2017, there was $40$135 million of borrowings under Generation’s bilateral credit facilities.
Borrowings under Exelon Corporate’s, Generation’s, ComEd’s, PECO’s, BGE’s, Pepco’s, DPL’s, and ACE’s revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table:
Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL | ACE | |||||||||||||||||||||||||
Prime based borrowings | 27.5 | 27.5 | 7.5 | 0.0 | 0.0 | 7.5 | 7.5 | 7.5 | ||||||||||||||||||||||||
LIBOR-based borrowings | 127.5 | 127.5 | 107.5 | 90.0 | 100.0 | 107.5 | 107.5 | 107.5 |
The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 90 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower.
Each revolving credit agreement for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the
twelve-month period ended on the last day of any quarter. The following table summarizes the minimum thresholds reflected in the credit agreements for the ninethree months ended September 30, 2016:March 31, 2017:
Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL | ACE | |||||||||||||||||||||||||
Credit agreement threshold | 2.50 to 1 | 3.00 to 1 | 2.00 to 1 | 2.00 to 1 | 2.00 to 1 | 2.00 to 1 | 2.00 to 1 | 2.00 to 1 |
At September 30, 2016,March 31, 2017, the interest coverage ratios at Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE were as follows:
Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL | ACE | |||||||||||||||||||||||||
Interest coverage ratio | 7.25 | 11.67 | 7.60 | 9.16 | 10.76 | 6.19 | 8.26 | 5.60 |
Exelon | Generation | ComEd | PECO | BGE | Pepco | DPL | ACE | |||||||||||||||||||||||||
Interest coverage ratio | 6.64 | 11.29 | 7.25 | 8.84 | 10.85 | 6.93 | 8.69 | 6.23 |
An event of default under Exelon, Generation, ComEd, PECO or BGE’s indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation will constitute an event of default under the Exelon Corporate credit facility. An event of default under Pepco, DPL or ACE’s indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $50 million in the aggregate will constitute an event of default under the credit facility.
The absence of a material adverse change in Exelon’s or PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.
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 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
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 intercompany money pools. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of September 30, 2016,March 31, 2017, are presented in the following table:
Exelon Intercompany Money Pool | During the Three Months Ended September 30, 2016 | As of September 30, 2016 | ||||||||||
Contributed (borrowed) | Maximum Contributed | Maximum Borrowed | Contributed (Borrowed) | |||||||||
Exelon Corporate | $ | 1,138 | n/a | $ | 708 | |||||||
Generation | — | (1,007 | ) | (461 | ) | |||||||
PECO | 210 | — | — | |||||||||
BSC | — | (378 | ) | (303 | ) | |||||||
PHI Corporate(a) | n/a | (53 | ) | (7 | ) | |||||||
PCI(a) | 63 | — | 63 |
Contributed (borrowed) Exelon Corporate Generation PECO BSC PHI Corporate(a) PCI(a)Exelon Intercompany Money Pool During the Three Months Ended
March 31, 2017 As of March 31,
2017 Maximum
Contributed Maximum
Borrowed Contributed
(Borrowed) $ 379 n/a $ 330 — (245 ) (54 ) 180 — — — (423 ) (317 ) n/a (47 ) (13 ) 55 — 54
(a) | As a result of the merger, PHI Corporate and PCI began to participate in the Exelon Intercompany Money Pool effective March 24, 2016. |
PHI Intercompany Money Pool | During the Three Months Ended September 30, 2016 | As of September 30, 2016 | During the Three Months Ended March 31, 2017 | As of March 31, 2017 | ||||||||||||||||||||
Contributed (borrowed) | Maximum Contributed | Maximum Borrowed | Contributed (Borrowed) | Maximum Contributed | Maximum Borrowed | Contributed (Borrowed) | ||||||||||||||||||
PHI Corporate | $ | 44 | n/a | $ | — | $ | 46 | $ | — | $ | 32 | |||||||||||||
Pepco | — | — | — | — | — | — | ||||||||||||||||||
DPL | — | — | — | — | — | — | ||||||||||||||||||
ACE | — | — | — | — | — | — | ||||||||||||||||||
PHISCO | 26 | (44 | ) | — | 1 | (46 | ) | (32 | ) |
Investments in Nuclear Decommissioning Trust Funds
Exelon, Generation and CENG maintain trust funds, as required by the NRC, to fund certain costs of decommissioning nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with Generation’s NDT fund investment policy. Generation’s and CENG’s investment policies establish limits on the concentration of holdings in any one company and also in any one industry. See Note 12 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for further information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.
Shelf Registration Statements
Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and DPLACE have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 2019. 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
Generation, 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:
Short-term Financing Authority(a) | Long-term Financing Authority | Short-term Financing Authority(a) | Long-term Financing Authority | |||||||||||||||||||||||||||||
Commission | Expiration Date | Amount (in millions) | Commission | Expiration Date | Amount (in millions) | Commission | Expiration Date | Amount (in millions) | Commission | Expiration Date | Amount (in millions) | |||||||||||||||||||||
ComEd(b) | FERC | December 31, 2017 | $2,500 | ICC | 2019 | $2,383 | FERC | December 31, 2017 | $ | 2,500 | ICC | 2019 | $ | 2,383 | ||||||||||||||||||
PECO | FERC | December 31, 2017 | 1,500 | PAPUC | December 31, 2018 | 1,600 | FERC | December 31, 2017 | 1,500 | PAPUC | December 31, 2018 | 1,600 | ||||||||||||||||||||
BGE | FERC | December 31, 2017 | 700 | MDPSC | N/A | — | FERC | December 31, 2017 | 700 | MDPSC | N/A | 1,000 | ||||||||||||||||||||
Pepco | FERC | June 30, 2018 | 500 | MDPSC / DCPSC | September 25, 2017 | 550 | FERC | June 30, 2018 | 500 | MDPSC / DCPSC | September 25, 2017 | 550 | ||||||||||||||||||||
DPL | FERC | June 30, 2018 | 500 | MDPSC / DPSC | December 31, 2017 | 300 | FERC | June 30, 2018 | 500 | MDPSC / DPSC | December 31, 2017 | 125 | ||||||||||||||||||||
ACE | NJPU | January 1, 2018 | 350 | NJBPU | December 31, 2017 | 300 | NJPU | January 1, 2018 | 350 | NJBPU | December 31, 2017 | 300 |
_________
(a) | Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority. |
(b) | ComEd had $1,565 million available in long-term debt refinancing authority and $818 million available in new money long term debt financing authority from the ICC as of |
Contractual Obligations andOff-Balance Sheet Arrangements
Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 2324 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 2015 2016Form 10-K and Note 16 — Commitments and Contingencies of the PHI 2015 Form 10-K for discussion of the Registrants’ commitments.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, PECO, and BGE 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 for further information.
For anin-depth discussion of the Registrants’ contractual obligations andoff-balance sheet arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations andOff-Balance Sheet Arrangements” in the Exelon 2015 2016Form 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Commercial Commitments” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Guarantees, Indemnifications and Off-Balance Sheet Arrangements” in the PHI 2015 Form 10-K.Commitments.”
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 the Registrants’ 2015Exelon’s 2016 Annual Report on Form10-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 amount of energy Exelon generates differs from the amount of energy it has contracted to sell, Exelon has price risk from commodity price movements. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel and other commodities.
Generation
Normal Operations and Hedging Activities. 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 price risk caused by market fluctuations, Generation enters intonon-derivative contracts as well as derivative contracts, including forwards, futures, swaps and options, with approved counterparties to hedge anticipated exposures. Generation believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 20162017 through 2018.2019.
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. As of September 30, 2016,March 31, 2017, the proportion of expected generation hedged is 98%-101%, 85%-88%97%-100%,60%-63% and 54%-57%30%-33% for 2016, 2017, 2018 and 2018,2019, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacitygenerating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options. Equivalent sales represent all hedging products, which include economic hedges and certainnon-derivative contracts including Generation’s sales to the Utility Registrants to serve their retail load.
A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entirenon-proprietary trading portfolio associated with a $5 reduction in the annual averagearound-the-clock energy price based on September 30, 2016March 31, 2017 market conditions and hedged position would be an increase inpre-tax net income of approximately $5$15 million for 20162017 and decreases of approximately $125$350 million and $415$665 million, respectively, for 20172018 and 2018.2019. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.
Proprietary Trading Activities. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop loss andValue-at-Risk (VaR) limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the proprietary trading activities. The proprietary trading activities, which included physical volumes of 1,5061,850 GWhs and 4,0151,220 GWhs for the three and nine months ended September 30,March 31, 2017 and 2016, respectively, and 1,913 GWhs and 5,378 GWhs for the three and nine months ended September 30, 2015, respectively, are a complement to Generation’s energy marketing portfolio, but represent a small portion of Generation’s overall revenue from energy marketing activities. Proprietary trading portfolio activity for the ninethree months ended September 30, 2016March 31, 2017 resulted in immaterialpre-tax gains due to netmark-to-market losses of $2 million and realized gains of $9 million due to net mark-to-market gains of $1 million and $8 million realized gains.$2 million. Generation uses a 95% confidence interval, assuming standard normal distribution, one day holding period and aone-tailed statistical measure in calculating its VaR. The daily VaR on proprietary trading activity averaged $0.3 million of exposure during the quarter. Generation has not segregated proprietary trading activity within the following discussion because of the relative size of the proprietary trading portfolio in comparison to Generation’s total Revenue net of purchase power and fuel expense from continuing operations for the ninethree months ended September 30, 2016March 31, 2017 of $6,754$2,090 million.
Fuel Procurement. Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potentialnon-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 57%49% of Generation’s uranium concentrate requirements from 20162017 through 20202021 are supplied by three producers. In the event ofnon-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 results of operations, cash flows and financial positions. See ITEM 7. — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information regarding uranium and coal supply agreement matters.
ComEd
ComEd entered into20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with nomark-up. The annual commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014. See Note 5 — Regulatory Matters and Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives. ComEd does not enter into derivatives for speculative or proprietary trading purposes.
PECO
PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. PECO has certain full requirements
contracts which are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basis of accounting. Under the DSP Programs, PECO is permitted to recover its electric supply procurement costs from retail customers with nomark-up.
PECO has also entered into derivative natural gas contracts, which either qualify for the normal purchases and normal sales exception or have nomark-to-market balances because the derivatives are index priced, to hedge its long-term price risk in the natural gas market. PECO’s hedging program for natural gas procurement has no direct impact on its financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.
PECO does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
BGE
BGE procures electric supply for default service customers through full requirements contracts pursuant to BGE’s MDPSC-approved SOS program. BGE’s full requirements contracts that are considered derivatives qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result, are accounted for on an accrual basis of accounting. Under the SOS program, BGE is permitted to recover its electricity procurement costs from retail customers, plus an administrative fee which includes a shareholder return component and an incremental cost component. However, through December 2016, BGE provides all residential electric customers a credit for the residential shareholder return component of the administrative charge.
BGE has also entered into derivative natural gas contracts, which qualify for the normal purchases and normal sales scope exception, to hedge its price risk in the natural gas market. The hedging program for natural gas procurement has no direct impact on BGE’s financial position. However, under BGE’s market-based rates incentive mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers.
BGE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
Pepco
Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco’s wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s price risk related to electric supply procurement is limited. Pepco locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.
Pepco does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
DPL
DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and the DPSC. The SOS rates charged recover DPL’s wholesale power supply costs. In Delaware, DPL is also entitled to recover a Reasonable Allowance for Retail Margin (RARM). The RARM includes a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. In Maryland, DPL charges an administrative fee intended to allow it to recover
its administrative costs. DPL locks in fixed prices for all of its SOS requirements through full requirements contracts. DPL’s price risk related to electric supply procurement is limited. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.
DPL provides natural gas to its customers under a GCR mechanism approved by the DPSC. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas.
DPL does not enter into derivatives for speculative or proprietary trading purposes. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives.
ACE
ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE’s wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS requirements through full requirements contracts. ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.
ACE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
Trading andNon-Trading Marketing Activities. The following detailed presentation of Exelon’s, Generation’s, ComEd’s, PHI’s and DPL’s trading andnon-trading marketing activities is 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, ComEd’s, PHI’s and DPL’s commoditymark-to-market net asset or liability balance sheet position from December 31, 20152016 to September 30, 2016.March 31, 2017. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates themark-to-market activities that are immediately recorded in earnings. This table excludes all normal purchase and normal sales contracts and does not segregate proprietary trading activity. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of themark-to-market energy contract net assets (liabilities) recorded as of September 30, 2016March 31, 2017 and December 31, 2015.2016.
Generation | ComEd | DPL(a) | Exelon(b) | Exelon | Generation | ComEd | PHI | DPL | ||||||||||||||||||||||||||||
Total mark-to-market energy contract net assets (liabilities) at December 31, 2015(c) | $ | 1,753 | $ | (247 | ) | $ | — | $ | 1,506 | |||||||||||||||||||||||||||
Total change in fair value during 2016 of contracts recorded in results of operations | 181 | — | — | 181 | ||||||||||||||||||||||||||||||||
Reclassification to realized at settlement of contracts recorded in results of operations | (284 | ) | — | — | (284 | ) | ||||||||||||||||||||||||||||||
Totalmark-to-market energy contract net assets (liabilities) at December 31, 2016(a) | $ | 719 | $ | 977 | $ | (258 | ) | $ | — | $ | — | |||||||||||||||||||||||||
Total change in fair value during 2017 of contracts recorded in results of operations | (42 | ) | (42 | ) | — | — | — | |||||||||||||||||||||||||||||
Reclassification to realized of contracts recorded in results of operations | (6 | ) | (6 | ) | — | — | — | |||||||||||||||||||||||||||||
Contracts received at acquisition date | (59 | ) | — | — | (59 | ) | — | — | — | — | — | |||||||||||||||||||||||||
Changes in fair value — recorded through regulatory assets and liabilities | — | 3 | 3 | 3 | (26 | ) | — | (24 | ) | (2 | ) | (2 | ) | |||||||||||||||||||||||
Changes in allocated collateral | (749 | ) | — | (3 | ) | (749 | ) | 117 | 115 | — | 2 | 2 | ||||||||||||||||||||||||
Changes in net option premium paid/(received) | 24 | — | — | 24 | 6 | 6 | — | — | — | |||||||||||||||||||||||||||
Option premium amortization | 20 | — | — | 20 | 4 | 4 | — | — | — | |||||||||||||||||||||||||||
Upfront payments and amortizations | 102 | — | — | 102 | (43 | ) | (43 | ) | — | — | — | |||||||||||||||||||||||||
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Total mark-to-market energy contract net assets (liabilities) at September 30, 2016(c) | $ | 988 | $ | (244 | ) | $ | — | $ | 744 | |||||||||||||||||||||||||||
Totalmark-to-market energy contract net assets (liabilities) at March 31, 2017(a) | $ | 729 | $ | 1,011 | $ | (282 | ) | $ | — | $ | — | |||||||||||||||||||||||||
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Amounts are shown net of collateral paid to and received from counterparties. |
For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of |
Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated |
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Fair Values. The following tables present maturity and source of fair value for Exelon, Generation and ComEdmark-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’ totalmark-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 thesemark-to-market amounts will settle and either generate or require cash. See Note 8 — 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 | Maturities Within | Total Fair Value | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
2016 | 2017 | 2018 | 2019 | 2020 | 2021 and Beyond | Total Fair Value | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 and Beyond | ||||||||||||||||||||||||||||||||||||||||||||
Normal Operations, Commodity derivative contracts(a)(b): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Actively quoted prices (Level 1) | $ | (9 | ) | $ | 26 | $ | (35 | ) | $ | (38 | ) | $ | (13 | ) | $ | 1 | $ | (68 | ) | $ | 100 | $ | (8 | ) | $ | (39 | ) | $ | (16 | ) | $ | (1 | ) | $ | — | $ | 36 | |||||||||||||||||||
Prices provided by external sources (Level 2) | 39 | 115 | 3 | (34 | ) | (2 | ) | — | 121 | 283 | 121 | 8 | (3 | ) | 1 | — | 410 | |||||||||||||||||||||||||||||||||||||||
Prices based on model or other valuation methods (Level 3)(c) | 70 | 435 | 202 | 64 | 12 | (92 | ) | 691 | 145 | 224 | 73 | 13 | (29 | ) | (143 | ) | 283 | |||||||||||||||||||||||||||||||||||||||
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Total | $ | 100 | $ | 576 | $ | 170 | $ | (8 | ) | $ | (3 | ) | $ | (91 | ) | $ | 744 | $ | 528 | $ | 337 | $ | 42 | $ | (6 | ) | $ | (29 | ) | $ | (143 | ) | $ | 729 | ||||||||||||||||||||||
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(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 againstmark-to-market assets and liabilities) of |
(c) | Includes ComEd’s net |
Generation
Maturities Within | Maturities Within | Total Fair Value | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
2016 | 2017 | 2018 | 2019 | 2020 | 2021 and Beyond | Total Fair Value | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 and Beyond | ||||||||||||||||||||||||||||||||||||||||||||
Normal Operations, Commodity derivative contracts(a)(b): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Actively quoted prices (Level 1) | $ | (9 | ) | $ | 26 | $ | (35 | ) | $ | (38 | ) | $ | (13 | ) | $ | 1 | $ | (68 | ) | $ | 100 | $ | (8 | ) | $ | (39 | ) | $ | (16 | ) | $ | (1 | ) | $ | — | $ | 36 | |||||||||||||||||||
Prices provided by external sources (Level 2) | 39 | 115 | 3 | (34 | ) | (2 | ) | — | 121 | 283 | 121 | 8 | (3 | ) | 1 | — | 410 | |||||||||||||||||||||||||||||||||||||||
Prices based on model or other valuation methods (Level 3) | 77 | 454 | 221 | 83 | 31 | 69 | 935 | 160 | 244 | 94 | 34 | (7 | ) | 40 | 565 | |||||||||||||||||||||||||||||||||||||||||
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Total | $ | 107 | $ | 595 | $ | 189 | $ | 11 | $ | 16 | $ | 70 | $ | 988 | $ | 543 | $ | 357 | $ | 63 | $ | 15 | $ | (7 | ) | $ | 40 | $ | 1,011 | |||||||||||||||||||||||||||
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(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 againstmark-to-market assets and liabilities) of |
ComEd
Maturities Within | Total Fair Value | Maturities Within | Total Fair Value | |||||||||||||||||||||||||||||||||||||||||||||||||||||
2016 | 2017 | 2018 | 2019 | 2020 | 2021 and Beyond | 2017 | 2018 | 2019 | 2020 | 2021 | �� | 2022 and Beyond | ||||||||||||||||||||||||||||||||||||||||||||
Commodity derivative contracts(a): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Prices based on model or other valuation methods (Level 3) | $ | (7 | ) | $ | (19 | ) | $ | (19 | ) | $ | (19 | ) | $ | (19 | ) | $ | (161 | ) | $ | (244 | ) | $ | (15 | ) | $ | (20 | ) | $ | (21 | ) | $ | (21 | ) | $ | (22 | ) | $ | (183 | ) | $ | (282 | ) |
(a) | Represents ComEd’s net liabilities associated with thefloating-to-fixed energy swap contracts with unaffiliated suppliers. |
Credit Risk, Collateral and Contingent Related Features (All Registrants)
The Registrants would be exposed to credit-related losses in the event ofnon-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented
by the fair value of contracts at the reporting date. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk, collateral and contingent related features.
Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2016.March 31, 2017. 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, NYMEX, ICE, NASDAQ, NGX and Nodal 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 $13 million, $31 million, $24 million, $45$40 million, $22 million, $47 million, $12$13 million, and $10$7 million as of September 30, 2016,March 31, 2017, respectively.
Rating as of September 30, 2016 | 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 March 31, 2017 | 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 | $ | 1,017 | $ | 4 | $ | 1,013 | 1 | $ | 355 | $ | 964 | $ | 16 | $ | 948 | 1 | $ | 313 | ||||||||||||||||||||||
Non-investment grade | 175 | 22 | 153 | — | — | 75 | 3 | 72 | — | — | ||||||||||||||||||||||||||||||
No external ratings | ||||||||||||||||||||||||||||||||||||||||
Internally rated — investment grade | 423 | 3 | 420 | — | — | 324 | — | 324 | — | — | ||||||||||||||||||||||||||||||
Internally rated — non-investment grade | 61 | 3 | 58 | — | — | 127 | 14 | 113 | — | — | ||||||||||||||||||||||||||||||
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Total | $ | 1,676 | $ | 32 | $ | 1,644 | 1 | $ | 355 | $ | 1,490 | $ | 33 | $ | 1,457 | 1 | $ | 313 | ||||||||||||||||||||||
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Maturity of Credit Risk Exposure | Maturity of Credit Risk Exposure | |||||||||||||||||||||||||||||||
Rating as of September 30, 2016 | Less than 2 Years | 2-5 Years | Exposure Greater than 5 Years | Total Exposure Before Credit Collateral | ||||||||||||||||||||||||||||
Rating as of March 31, 2017 | Less than 2 Years | 2-5 Years | Exposure Greater than 5 Years | Total Exposure Before Credit Collateral | ||||||||||||||||||||||||||||
Investment grade | $ | 769 | $ | 242 | $ | 6 | $ | 1,017 | $ | 753 | $ | 208 | $ | 3 | $ | 964 | ||||||||||||||||
Non-investment grade | 122 | 53 | — | 175 | 62 | 13 | — | 75 | ||||||||||||||||||||||||
No external ratings | ||||||||||||||||||||||||||||||||
Internally rated — investment grade | 353 | 47 | 23 | 423 | 253 | 46 | 25 | 324 | ||||||||||||||||||||||||
Internally rated — non-investment grade | 43 | 18 | — | 61 | 93 | 34 | — | 127 | ||||||||||||||||||||||||
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Total | $ | 1,287 | $ | 360 | $ | 29 | $ | 1,676 | $ | 1,161 | $ | 301 | $ | 28 | $ | 1,490 | ||||||||||||||||
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Net Credit Exposure by Type of Counterparty | As of September 30, 2016 | As of March 31, 2017 | ||||||
Financial institutions | $ | 117 | $ | 101 | ||||
Investor-owned utilities, marketers, power producers | 757 | 600 | ||||||
Energy cooperatives and municipalities | 712 | 663 | ||||||
Other | 58 | 93 | ||||||
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Total | $ | 1,644 | $ | 1,457 | ||||
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(a) | As of |
ComEd, PECO, BGE, PHI, Pepco, DPL and BGEACE
There have been no significant changes or additions to ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s or BGE’sACE’s exposures to credit risk that are described in ITEM 1A. RISK FACTORS of Exelon’s 20152016 Annual Report on Form10-K.
See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.
PHI, Pepco, DPL and ACE
There have been no significant changes or additions to PHI’s, Pepco’s, DPL’s or ACE’s exposures to credit risk as described in ITEM 1A. RISK FACTORS of PHI’s 2015 Annual Report on Form 10-K.
See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.
Collateral (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. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. 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 expresslyagreed-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. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding collateral requirements.
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 results of operations, cash flows and financial position. 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. In order to post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities for additional information.
As of September 30, 2016,March 31, 2017, Generation had cash collateral of $501$471 million posted and cash collateral held of $18$35 million for external counterparties with derivative positions, of which $485$444 million and $3 millionan immaterial amount in net cash collateral deposits were offset against energy derivative and interest rate and foreign exchange derivative related to underlying energy contracts, respectively. As of September 30, 2016, $5March 31, 2017, $8 million of cash collateral held was not offset against net derivative positions because it was not associated with energy-related derivatives or as of the balance sheet date there were no positions to offset. See Note 1817 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.
ComEd
As of September 30, 2016,March 31, 2017, ComEd held $3$1 million in collateral from suppliers in association with energy procurement contracts and held approximately $19 million in the form of cash and letters of credit for both annual and long-term renewable
energy contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements in this report and Note 3 — Regulatory Matters of the 20152016 Exelon Form10-K for additional information.
PECO
As of September 30, 2016,March 31, 2017, PECO was not required to post collateral under its energy and natural gas procurement contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
BGE
BGE is not required to post collateral under its electric supply contracts.contracts nor was it holding collateral under its electric supply procurement contracts as of March 31, 2017. As of September 30, 2016,March 31, 2017, BGE was not required to post collateral under its natural gas procurement contracts norbut was it holding an immaterial amount of collateral under its electric supply and natural gas procurement contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Pepco
Pepco is not required to post collateral under its energy procurement contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
DPL
DPL is not required to post collateral under its energy procurement contracts. As of September 30, 2016,March 31, 2017, DPL was not required to post collateral under its natural gas procurement contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
ACE
ACE is not required to post collateral under its energy procurement contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
RTOs and ISOs (All Registrants)
Generation, ComEd, PECO, BGE, Pepco, DPL and ACE participate in all, or some, of the established real-timewholesale spot energy markets that are administered by PJM,ISO-NE,ISO-NY, CAISO, MISO, SPP, AESO, OIESO and ERCOT. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that are operatedadministered by the RTOs or ISOs, as applicable. In areas where there isare no spot market,energy markets, electricity is purchased and sold solely through bilateral agreements. For sales into the spot energy markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants.Non-performance ornon-payment by a major counterparty could result in a material adverse impact on the Registrants’ results of operations, cash flows and financial positions.
Exchange Traded Transactions (Exelon, Generation, PHI and DPL)
Generation enters into commodity transactions on NYMEX, ICE, NASDAQ, NGX and the Nodal exchange.exchange (“the Exchanges”). DPL enters into commodity transactions on ICE. The NYMEX, ICE and Nodal exchangeExchange clearinghouses act as the counterparty to each trade. Transactions on the NYMEX, ICE and Nodal exchangeExchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on NYMEX, ICE and Nodal exchangethe Exchanges are significantly collateralized and have limited counterparty credit risk.
Long-Term Leases (Exelon)
On March 31, 2016, UII and MEAG finalized an agreement to terminate the MEAG Headleases, the MEAG Leases, and other related agreements prior to their expiration dates. As a result of the lease termination, UII received an early termination payment of $360 million from MEAG and wrote-off the $356 million net investment in the MEAG Headleases and the Leases. The transaction resulted in a pre-tax gain of $4 million which is reflected in Operating and maintenance expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income. See Note 6 — Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Interest Rate and Foreign Exchange Risk (Exelon, Generation, ComEd, PECO, BGE and PHI)(All Registrants)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Exelon registrantsRegistrants may also utilizefixed-to-floating interest rate swaps, which are typically designated as fair value
hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At September 30, 2016,March 31, 2017, Exelon had $800 million of notional amounts offixed-to-floating hedges outstanding and Exelon and Generation had $672$657 million of notional amounts offloating-to-fixed hedges outstanding, respectively.outstanding. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) andfixed-to-floating swaps would result in approximately a $5$2 million decrease in Exelon Consolidatedpre-tax income for the ninethree months ended September 30, 2016.March 31, 2017. 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.
Equity Price Risk (Exelon and Generation)
Exelon and Generation maintainmaintains trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’sits nuclear plants. As of September 30, 2016,March 31, 2017, Generation’s decommissioning trust funds are reflected at fair value on 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% increase in interest rates and decrease in equity prices would result in a $535$595 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 ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for further discussion of equity price risk as a result of the current capital and credit market conditions.
Item 4. Controls and Procedures
Item 4. | Controls and Procedures |
During the thirdfirst quarter of 2016,2017, each of Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s and ACE’s 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 all 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, 2016,March 31, 2017, the principal executive officer and principal financial officer of each of Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. All 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. On March 23, 2016, the merger between Exelon and PHI closed. Exelon is currently in the process of integrating PHI’s operations, processes and internal controls. There have been no changes in internal control over financial reporting that occurred during the third quarter of 2016, other than changes resulting from the PHI Merger, 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’s internal control over financial reporting. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for further information regarding the PHI acquisition. Exelon’s management expects that the controls over financial reporting associated with PHI, Pepco, DPL and ACE from the date of the merger forward will be covered in the year-end assessment.
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 2015 2016Form 10-K and (b) ITEM 3. LEGAL PROCEEDINGS of PHI’s 2015 Form 10-K and (c) Notes 5 — Regulatory Matters and 1817 — 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
Exclusive ofAt March 31, 2017, the Risks Related toRegistrants’ risk factors were consistent with the Pending Merger with PHIrisk factors described in Exelon’s 2015 the Registrants’ combined 2016Form 10-K in ITEM 1A. RISK FACTORS, Exelon is, and will continue to be, subject to the risks described in Exelon’s and PHI’s 2015 Form 10-K in (a) ITEM 1A. RISK FACTORS, (b) ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS and (c) ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA: Note 23 of the Combined Notes to Consolidated Financial Statements in Exelon’s 2015 Form 10-K and Note 16 of the Notes to Consolidated Financial Statements in PHI’s 2015 Form 10-K. As a result of the recent Tax Court decision on Exelon’s like-kind exchange position, Exelon and ComEd have revised the description of their risk related to the 1999 sale of ComEd’s fossil generating assets. In addition, due to the close of the PHI merger on March 23, 2016, Exelon is subject to additional risks related to the merger as described below.FACTORS.
Market and Financial Factors
Challenges to tax positions taken by the Registrants as well as tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions, could negatively impact the Registrants’ results of operations or cash flows. (Exelon, Generation, ComEd, PECO and BGE)
1999 sale of fossil generating assets.On September 19, 2016, the Tax Court rejected Exelon’s like-kind exchange position and ruled that Exelon was not entitled to defer gain on the transaction. In addition, contrary to Exelon’s evaluation that the penalty was unwarranted, the Tax Court ruled that Exelon is liable for the penalty and after-tax interest due on the asserted penalty. In early 2017, Exelon expects to timely appeal this decision to the U.S. Court of Appeals for the Seventh Circuit.
In order to appeal the Tax Court’s like-kind exchange decision, Exelon is required to pay the tax, penalty and interest for the tax years before the Court at the time Exelon files its appeal (expected early 2017). Exelon deposited with the IRS approximately $1,250 million in October 2016. The total amount of tax, penalty and interest payable is currently being computed pursuant to the Tax Court rules. Any remaining amounts due, which are not expected to be materially different from the amount deposited, will be paid in early 2017 at the time Exelon files its appeal of the Tax Court decision. If Exelon’s deposit exceeds the final Tax Court computation, Exelon can request a return of the excess.
Risks Related to the PHI Merger
The merger may not achieve its anticipated results, and Exelon may be unable to integrate the operations of PHI in the manner expected.
Exelon and PHI entered into the merger agreement with the expectation that the merger will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Exelon and PHI can be integrated in an efficient, effective and timely manner.
It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of Exelon’s businesses, processes and systems or inconsistencies in standards, controls, procedures, practices and policies, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the merger as and when expected. Exelon may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs and could adversely affect Exelon’s future business, financial condition, operating results and prospects.
The merger may not be accretive to earnings and may cause dilution to Exelon’s earnings per share, which may negatively affect the market price of Exelon’s common stock.
The timing and amount of accretion expected could be significantly adversely affected by a number of uncertainties, including market conditions, risks related to Exelon’s businesses and whether the business of PHI is integrated in an efficient and effective manner. Exelon also could encounter additional transaction and integration-related costs, may fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates. Any of these factors could cause a decrease in Exelon’s adjusted earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of Exelon’s common stock.
Exelon may incur unexpected transaction fees and merger-related costs in connection with the merger.
Exelon expects to incur a number of non-recurring expenses associated with completing the merger, as well as expenses related to combining the operations of the two companies. Exelon may incur additional unanticipated costs in the integration of the businesses of Exelon and PHI. Although Exelon expects that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction and merger-related costs over time, the combined company may not achieve this net benefit in the near term, or at all.
Exelon may encounter unexpected difficulties or costs in meeting commitments it made under various orders and agreements associated with regulatory approvals for the PHI Merger.
As a result of the process to obtain regulatory approvals required for the PHI Merger, Exelon is committed to various programs, contributions and investments in several settlement agreements and regulatory approval orders. It is possible that Exelon may encounter delays, unexpected difficulties, or additional costs in meeting these commitments in compliance with the terms of the relevant agreements and orders. Failure to fulfill the commitments in accordance with their terms could result in increased costs or result in penalties or fines that could adversely affect Exelon’s financial position and operating results.
Item 4. | Mine Safety Disclosures |
Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACEAll Registrants
Not applicable to the Registrants.
Item 5. | Other Information |
Exelon and Generation
See Note 10 — Debt and Credit Agreements and Note 20 — Subsequent Events of the Combined Notes to the Consolidated Financial Statements for recent developments related to EGTP.
Item 6. | Exhibits |
Certain of the following exhibits are incorporated herein by reference under Rule12b-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 | |
4.1 | Form of | |
4.2 | Form of | |
4.3 | ||
| ||
4.5 | One Hundred and Nineteenth Supplemental Indenture, dated April 5, 2017, between DPL and The Bank of New York Mellon, trustee | |
101.INS | XBRL Instance | |
101.SCH | XBRL Taxonomy Extension Schema | |
101.CAL | XBRL Taxonomy Extension Calculation | |
101.DEF | XBRL Taxonomy Extension Definition | |
101.LAB | XBRL Taxonomy Extension Labels | |
101.PRE | XBRL Taxonomy Extension Presentation |
Certifications Pursuant toRule 13a-14(a) and15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form10-Q for the quarterly period ended September 30, 2016March 31, 2017 filed by the following officers for the following companies:
31-1 | — Filed by Christopher M. Crane for Exelon Corporation | |
31-2 | — Filed by Jonathan W. Thayer for Exelon Corporation | |
31-3 | — Filed by Kenneth W. Cornew for Exelon Generation Company, LLC | |
31-4 | — Filed by Bryan P. Wright for Exelon Generation Company, LLC | |
31-5 | — Filed by Anne R. Pramaggiore for Commonwealth Edison Company | |
31-6 | — Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company | |
31-7 | — Filed by Craig L. Adams for PECO Energy Company | |
31-8 | — Filed by Phillip S. Barnett for PECO Energy Company | |
31-9 | — Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company | |
31-10 | — Filed by David M. Vahos for Baltimore Gas and Electric Company | |
31-11 | — Filed by David M. Velazquez for Pepco Holdings LLC | |
31-12 | — Filed by Donna J. Kinzel for Pepco Holdings LLC | |
31-13 | — Filed by David M. Velazquez for Potomac Electric Power Company | |
31-14 | — Filed by Donna J. Kinzel for Potomac Electric Power Company | |
31-15 | — Filed by David M. Velazquez for Delmarva Power & Light Company | |
31-16 | — Filed by Donna J. Kinzel for Delmarva Power & Light Company | |
31-17 | — Filed by David M. Velazquez for Atlantic City Electric Company | |
31-18 | — Filed by Donna J. Kinzel for Atlantic City Electric Company |
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2016March 31, 2017 filed by the following officers for the following companies:
32-1 | — Filed by Christopher M. Crane for Exelon Corporation | |
32-2 | — Filed by Jonathan W. Thayer for Exelon Corporation | |
32-3 | — Filed by Kenneth W. Cornew for Exelon Generation Company, LLC | |
32-4 | — Filed by Bryan P. Wright for Exelon Generation Company, LLC | |
32-5 | — Filed by Anne R. Pramaggiore for Commonwealth Edison Company | |
32-6 | — Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company | |
32-7 | — Filed by Craig L. Adams for PECO Energy Company | |
32-8 | — Filed by Phillip S. Barnett for PECO Energy Company | |
32-9 | — Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company | |
32-10 | — Filed by David M. Vahos for Baltimore Gas and Electric Company | |
32-11 | — Filed by David M. Velazquez for Pepco Holdings LLC | |
32-12 | — Filed by Donna J. Kinzel for Pepco Holdings LLC | |
32-13 | — Filed by David M. Velazquez for Potomac Electric Power Company | |
32-14 | — Filed by Donna J. Kinzel for Potomac Electric Power Company | |
32-15 | — Filed by David M. Velazquez for Delmarva Power & Light Company | |
32-16 | — Filed by Donna J. Kinzel for Delmarva Power & Light Company | |
32-17 | — Filed by David M. Velazquez for Atlantic City Electric Company | |
32-18 | — Filed by Donna J. Kinzel for Atlantic City Electric Company |
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.
/S/ CHRISTOPHER M. CRANE | /S/ JONATHAN W. THAYER | |
Christopher M. Crane | Jonathan W. Thayer | |
President and Chief Executive Officer (Principal Executive Officer) and Director | Senior Executive Vice President and Chief Financial Officer (Principal Financial Officer) | |
/S/ DUANE M. D | ||
Duane M. DesParte | ||
Senior Vice President and Corporate Controller (Principal Accounting Officer) |
October 26, 2016May 3, 2017
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. CORNEW | /S/ BRYAN P. WRIGHT | |
Kenneth W. Cornew | Bryan P. Wright | |
President and Chief 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 26, 2016May 3, 2017
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.
/S/ ANNE R. PRAMAGGIORE | /S/ JOSEPH R. TRPIK, JR. | |
Anne R. Pramaggiore | Joseph R. Trpik, Jr. | |
President and Chief Executive Officer (Principal Executive Officer) | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | |
/S/ GERALD J. KOZEL | ||
Gerald J. Kozel | ||
Vice President and Controller (Principal Accounting Officer) |
October 26, 2016May 3, 2017
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.
/S/ CRAIG L. ADAMS | /S/ PHILLIP S. BARNETT | |
Craig L. Adams | Phillip S. Barnett | |
President and Chief Executive Officer (Principal Executive Officer) and Director | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | |
/S/ SCOTT A. BAILEY | ||
Scott A. Bailey | ||
Vice President and Controller (Principal Accounting Officer) |
October 26, 2016May 3, 2017
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. | /S/ DAVID M. VAHOS | |
Calvin G. Butler, Jr. | David M. Vahos | |
Chief Executive Officer (Principal Executive Officer) | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | |
/S/ ANDREW W. HOLMES | ||
Andrew W. Holmes | ||
Vice President and Controller (Principal Accounting Officer) |
October 26, 2016May 3, 2017
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.
/S/ DAVID M. VELAZQUEZ | /S/ DONNA J. KINZEL | |
David M. Velazquez | Donna J. Kinzel | |
President and Chief Executive Officer (Principal Executive Officer) | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | |
/S/ ROBERT M. AIKEN | ||
Robert M. Aiken | ||
Vice President and Controller (Principal Accounting Officer) |
October 26, 2016May 3, 2017
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/ DONNA J. KINZEL | |
David M. Velazquez | Donna J. Kinzel | |
President and Chief Executive Officer (Principal Executive Officer) | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | |
/S/ ROBERT M. AIKEN | ||
Robert M. Aiken | ||
Vice President and Controller (Principal Accounting Officer) |
October 26, 2016May 3, 2017
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/ DONNA J. KINZEL | |
David M. Velazquez | Donna J. Kinzel | |
President and Chief Executive Officer (Principal Executive Officer) | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) | |
/S/ ROBERT M. AIKEN | ||
Robert M. Aiken | ||
Vice President and Controller (Principal Accounting Officer) |
October 26, 2016May 3, 2017
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/ DONNA J. KINZEL | |
David M. Velazquez | Donna J. Kinzel | |
President and Chief Executive Officer (Principal Executive Officer) | Senior Vice President, Chief Financial Officer and Treasurer | |
/S/ ROBERT M. AIKEN | ||
Robert M. Aiken | ||
Vice President and Controller (Principal Accounting Officer) |
October 26, 2016May 3, 2017
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